Form: 20FR12B

Form for initial registration of a class of securities of foreign private issuers pursuant to Section 12(b)

November 16, 2023

Documents

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 20-F
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(Mark One)
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REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934​
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OR
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934​
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For the fiscal year ended
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934​
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OR
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SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934​
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Date of event requiring this shell company report
For the transition period from        to       
Commission file number:
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[MISSING IMAGE: lg_diversifiedenergy-4c.jpg]
Diversified Energy Company plc
(Exact name of Registrant as specified in its charter)​
Not Applicable
(Translation of Registrant’s name into English)​
England and Wales
(Jurisdiction of incorporation or organization)​
1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909
(Address of principal executive offices)​
Bradley G. Gray
Diversified Energy Company plc
1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)​
Securities registered or to be registered, pursuant to Section 12(b) of the Act
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Title of each class
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Trading Symbol(s)
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Name of each exchange on which registered
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Ordinary shares, nominal (par) value £0.01 per share
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DEC
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New York Stock Exchange
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Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital stock or common stock as of the close of the period covered by the annual report: N/A
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ☐ No ☒
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.  Yes ☐ No ☐
Note — Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☐ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☐ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
​ ☐ Large accelerated filer ​ ​ ☐ Accelerated filer ​ ​ ☒ Non-accelerated filer ​ ​
☐ Emerging growth company
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If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.  ☐
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
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U.S. GAAP
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International Financial Reporting Standards as issued by the International Accounting Standards Board
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Other
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If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow.  Item 17 ☐  Item 18 ☐
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐ No ☐
(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  Yes ☐ No ☐
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CONTENTS
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COMMONLY USED DEFINED TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the natural gas and oil industry:
“Basin.” A large natural depression on the earth’s surface in which sediments accumulate.
“Bbl.” Barrel or barrels of oil or natural gas liquids.
“Boe.” Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
“Boepd.” Barrel of oil equivalent per day.
“Btu or British Thermal Unit.” A British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
“Development wells.” Wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“Drilling.” means any activity related to drilling pad make-ready costs, rig mobilization and creating a wellbore in order to facilitate the ultimate production of hydrocarbons.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses, taxes and the royalty burden.
“E&P.” Exploration and production of natural gas, NGLs and oil.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
“Gross acres or gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Henry Hub.” A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a high angle to vertical (which can be greater than 90 degrees) in order to stay with a specified interval.
“Hydraulic fracturing.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
“IFRS.” International Financial Reporting Standards, as issued by the International Accounting Standards Board.
“IASB.” The International Accounting Standards Board.
“LIBOR.” London Inter-bank Offered Rate, which is a market rate of interest.
“MBbls.” One thousand barrels of oil, condensate or NGL.
“Mboe.” One thousand Boe.
 
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“Mboepd.” One thousand Boe per day.
“Mcf.” One thousand cubic feet of natural gas.
“Mcfe.” One thousand cubic feet of natural gas equivalent.
“MMBoe.” One million Boe.
“MMBtu.” One million British Thermal Units.
“MMcf.” One million cubic feet of natural gas.
“MMcfe.” One million cubic feet of natural gas equivalent.
“MMcfepd.” One million cubic feet of natural gas equivalent per day.
“Mont Belvieu.” A mature trading hub with a high level of liquidity and transparency that sets spot and futures prices for NGLs.
“MtCO2e.” Metric tons of carbon dioxide equivalent.
“Net acres or net wells.” The sum of the fractional working interest owned in gross acres or gross wells, as the case may be. For example, an owner who has a 50% interest in 100 acres owns 50 net acres and an owner who has a 50% interest in 100 wells owns 50 net wells.
“NGL or NGLs.” Natural gas liquids, such as ethane, propane, butane and natural gasoline that are extracted from natural gas production streams.
“NYMEX.” The New York Mercantile Exchange.
“Oil.” Includes crude oil and condensate.
“OPEC.” The Organization of the Petroleum Exporting Countries.
“Possible reserves.” Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(a)   When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(b)   Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(c)   Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(d)   The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(e)   Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(f)   Where direct observation has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally
 
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higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
“Probable Reserves.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(a)   When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(b)   Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(c)   Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Proved developed reserves.” Reserves of any category that can be expected to be recovered through:
(a)   existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(b)   installed extraction equipment and infrastructure operation at the time of the reserve estimate if the extraction is by means not involving a well.
“Proved reserves.” Those quantities of natural gas, NGLs and oil, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonable certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(a)   The area of reservoir considered as proved includes:
(i)   the area identified by drilling and limited by fluid contacts, if any, and
(ii)   adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas, NGLs or oil on the basis of available geosciences and engineering data.
(b)   In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(c)   Where direct observation from well penetrations has defined a HKO elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(d)   Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
 
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(i)   successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(ii)   the project has been approved for development by all necessary parties and entities, including governmental entities.
(e)   Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“Proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, NGLs or oil, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas, NGLs and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres, e.g., 40-acre spacing, and is established by regulatory agencies.
“SOFR.” The Secured Overnight Financing Rate, or SOFR.
“Standardized measure.” The year-end present value (discounted at an annual rate of 10%) of estimated future net cash flows to be generated from the production of proved reserves net of estimated income taxes associated with such net cash flows, as determined in accordance with FASB guidelines, without giving effect to non-property related expenses such as indirect general and administrative expenses and debt service or to depreciation, depletion and amortization. Standardized measure does not give effect to derivative transactions.
“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas, NGLs and oil regardless of whether such acreage contains proved reserves.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“U.S. GAAP.” Accounting principles generally accepted in the United States of America.
“Wellbore” or “well.” The hole drilled by the bit that is equipped for natural gas, NGLs or oil production on a completed well. Also called a well or borehole.
 
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“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas, NGLs, oil or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
“Workover.” Operations on a producing well to restore or increase production.
“WTI.” West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.
 
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ABOUT THIS REGISTRATION STATEMENT
Except where the context otherwise requires or where otherwise indicated, the terms “Diversified Energy,” the “Company,” “DEC,” “we,” “us,” “our company” and “our business” refer to Diversified Energy Company plc, formerly Diversified Gas & Oil plc, together with its consolidated subsidiaries.
For the convenience of the reader, in this registration statement, unless otherwise indicated, translations from pound sterling into U.S. dollars were made at the rate of £1.00 to $      , which was the noon buying rate of the Federal Reserve Bank of New York on           , 2023. Such U.S. dollar amounts are not necessarily indicative of the amounts of U.S. dollars that could actually have been purchased upon exchange of pound sterling at the dates indicated or any other date.
We obtained the industry, market and competitive position data in this registration statement from our own internal estimates, surveys and research, as well as from publicly available information, industry and general publications and research, surveys and studies.
Industry publications, research, surveys, studies and forecasts generally state that the information they contain has been obtained from sources believed to be reliable but that the accuracy and completeness of such information is not guaranteed. Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties as the other forward-looking statements in this registration statement. These forecasts and forward-looking information are subject to uncertainty and risk due to a variety of factors, including those described in the section titled “Risk Factors” found elsewhere in this registration statement. These and other factors could cause results to differ materially from those expressed in the forecasts or estimates from independent third parties and us.
We have proprietary rights to trademarks used in this registration statement that are important to our business, many of which are registered under applicable intellectual property laws. Solely for convenience, trademarks and trade names referred to in this registration statement may appear without the “®” or “™” symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent possible under applicable law, our rights or the rights of the applicable licensor to these trademarks and trade names. We do not intend our use or display of other companies’ trademarks, trade names or service marks to imply a relationship with, or endorsement or sponsorship of us by, any other companies. Each trademark, trade name or service mark of any other company appearing in this registration statement is the property of its respective holder.
Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and reserve data presented in this registration statement is as of December 31, 2022.
 
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Certain statements contained in this registration statement, including those in “Item 3.D. Risk Factors,” “Item 4.B. Business Overview” and “Item 5. Operating and Financial Review and Prospects” and elsewhere in this registration statement, contain forward-looking statements. In some cases, you can identify forward-looking statements by the following words: “may,” “might,” “will,” “could,” “would,” “should,” “expect,” “plan,” “anticipate,” “intend,” “seek,” “believe,” “estimate,” “predict,” “potential,” “continue,” “contemplate,” “possible” or the negative of these terms or other comparable terminology, although not all forward-looking statements contain these words. Forward-looking statements are not guarantees of performance. We have based forward-looking statements in this registration statement on our current expectations and beliefs about future developments and their potential effect on us.
These statements involve risks, uncertainties and other factors that may cause our actual results, levels of activity, performance or achievements to be materially different from the information expressed or implied by these forward-looking statements. Although we believe that we have a reasonable basis for each forward-looking statement contained in this registration statement, we caution you that these statements are based on a combination of facts and factors currently known by us and our projections of the future, about which we cannot be certain. Forward-looking statements contained in this registration statement are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties (some of which are beyond our control) and assumptions that could cause our actual results to differ materially from our historical experience and present expectations or projections. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements. Known material factors that could cause actual results to differ from those expressed in or implied by forward-looking statements contained or incorporated in this registration statement are described under “Risk Factors” and in other sections of this registration statement. Such factors include, but are not limited to:
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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 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.
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You should refer to “Item 3.D Risk Factors” of this registration statement for a discussion of other important factors that may cause our actual results to differ materially from those expressed or implied by our forward-looking statements. As a result of these factors, we cannot assure you that the forward-looking statements in this registration statement will prove to be accurate.
In addition, statements that “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based upon information available to us as of the date of this registration statement, and although we believe such information forms a reasonable basis for such statements, such information may be limited or incomplete, and our statements should not be read to indicate that we have conducted a thorough inquiry into, or review of, all potentially available relevant information. These statements are inherently uncertain, and investors are cautioned not to unduly rely upon these statements. Furthermore, if our forward-looking statements prove to be inaccurate, the inaccuracy may be material. In light of the significant uncertainties in these forward-looking statements, you should not regard these statements as a representation or warranty by us or any other person that we will achieve our objectives and plans in any specified time frame, or at all. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
 
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PRESENTATION OF FINANCIAL INFORMATION
This registration statement includes our audited consolidated financial statements as of December 31, 2022 and 2021 and for each of the three years in the period ended December 31, 2022 as well as our unaudited interim condensed consolidated financial statements as of June 30, 2023 and for the six months ended June 30, 2023 and 2022, which have been prepared in accordance with IFRS, as issued by the IASB, which differ in certain significant respects from U.S. GAAP. None of our financial statements were prepared in accordance with U.S. GAAP.
Our financial information is presented in U.S. dollars. Our fiscal year begins on January 1 and ends on December 31 of the same year. Certain amounts and percentages included in this registration statement have been rounded. Accordingly, in certain instances, the sum of the numbers in a column of a table may not exactly equal the total figure for that column.
All references in this registration statement to “$” mean U.S. dollars and all references to “£” and “GBP” mean pound sterling. We have made rounding adjustments to some of the figures included in this registration statement. Accordingly, numerical figures shown as totals in some tables may not be an arithmetic aggregation of the figures that preceded them.
Use of Non-IFRS Measures
Certain key operating metrics that are not defined under IFRS (alternative performance measures) are included in this registration statement. These non-IFRS measures are used by us to monitor the underlying business performance of the Company from period to period and to facilitate comparison with our peers. Since not all companies calculate these or other non-IFRS metrics in the same way, the manner in which we have chosen to calculate the non-IFRS metrics presented herein may not be compatible with similarly defined terms used by other companies. The non-IFRS metrics should not be considered in isolation of, or viewed as substitutes for, the financial information prepared in accordance with IFRS. Certain of the key operating metrics set forth below are based on information derived from our regularly maintained records and accounting and operating systems. See “Item 5. Operating and Financial Review and Prospects — A. Operating Results” for reconciliations of such measures to the most directly comparable IFRS measures and reasons for the use of such non-IFRS measures.
Adjusted EBITDA.   As used herein, EBITDA represents earnings before interest, taxes, depletion, depreciation and amortization. Adjusted EBITDA includes adjusting for items that are not comparable period over period, namely, accretion of asset retirement obligation, other (income) expense, loss on joint and working interest owners receivable, gain on bargain purchase, (gain) loss on fair value adjustments of unsettled financial instruments, (gain) loss on natural gas and oil property and equipment, costs associated with acquisitions, other adjusting costs, non-cash equity compensation, (gain) loss on foreign currency hedge, net (gain) loss on interest rate swaps and items of a similar nature.
Adjusted EBITDA should not be considered in isolation or as a substitute for operating profit or loss, net income or loss, or cash flows provided by operating, investing and financing activities. However, we believe such measure is useful to an investor in evaluating DEC’s financial performance because it (1) is widely used by investors in the natural gas and oil industry as an indicator of underlying business performance; (2) helps investors to more meaningfully evaluate and compare the results of DEC’s operations from period to period by removing the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement; (3) is used in the calculation of a key metric in our revolving credit facility by and among DP RBL Co LLC, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto (the “Credit Facility”) financial covenants; and (4) is used by the Company as a performance measure in determining executive compensation. When evaluating this measure, we believe investors also commonly find it useful to evaluate this metric as a percentage of our Total Revenue, inclusive of settled hedges, producing what we refer to as our Adjusted EBITDA Margin throughout this report. Please refer to the definitions of these added profitability metrics below for additional details.
Net Debt.   As used herein, Net Debt represents total debt as recognized on the balance sheet less cash and restricted cash. Total debt includes DEC’s borrowings under the Credit Facility and borrowings under
 
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or issuances of, as applicable, its subsidiaries’ securitization facilities. Net Debt is a useful indicator of DEC’s leverage and capital structure.
Total Revenue, inclusive of settled hedges.   As used herein, Total Revenue, inclusive of settled hedges, includes the impact of derivatives settled in cash. We believe that Total Revenue, inclusive of settled hedges, is a useful measure because it enables investors to discern DEC’s realized revenue after adjusting for the settlement of derivative contracts.
Adjusted EBITDA Margin.   As used herein, Adjusted EBITDA Margin is measured as Adjusted EBITDA, as a percentage of Total Revenue, inclusive of settled hedges. Adjusted EBITDA Margin includes the direct operating cost and the portion of general and administrative cost it takes to produce each Boe. This metric includes operating expense, employees, administrative costs and professional services and recurring allowance for credit losses, which include fixed and variable cost components. We believe that Adjusted EBITDA Margin is a useful measure of DEC’s profitability and efficiency as well as its earnings quality given its ability to measure the company on a more comparable basis period over period given we are often involved in transactions that are not comparable between periods.
Free Cash Flow.   As used herein, Free Cash Flow represents net cash provided by operating activities less expenditures on natural gas and oil properties and equipment and cash paid for interest. We believe that Free Cash Flow is a useful indicator of DEC’s ability to generate cash that is available for activities other than capital expenditures. Management believes that Free Cash Flow provides investors with an important perspective on the cash available to service debt obligations, make strategic acquisitions and investments and pay dividends.
Adjusted Operating Cost per Boe.   Adjusted Operating Cost per Boe is a metric that allows us to measure the direct operating cost and the portion of general and administrative cost it takes to produce each Boe. This metric, similar to Adjusted EBITDA Margin, includes operating expense, employees, administrative costs and professional services and recurring allowance for credit losses, which include fixed and variable cost components.
Employees, administrative costs and professional services.   As used herein, employees, administrative costs and professional services represents total administrative expenses excluding cost associated with acquisitions, other adjusting costs and non-cash expenses. We use Employees, administrative costs and professional services because this measure excludes items that affect the comparability of results or that are not indicative of trends in the ongoing business.
PV-10.   PV-10 is a non-IFRS measure because it excludes the effects of applicable income tax. Management believes that the presentation of the non-IFRS financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating natural gas and oil companies. PV-10 is not a measure of financial or operating performance under IFRS. PV-10 should not be considered as an alternative to the standardized measure as defined under IFRS. We have included a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, its most directly comparable IFRS measure, elsewhere in this registration statement. PV-10 differs from the standardized measure of discounted future net cash flows because it does not include the effects of income taxes. Neither PV-10 nor the standardized measure represents an estimate of fair market value of our natural gas and oil properties.
 
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PART I
Item 1.   Identity of Directors, Senior Management and Advisers
A.   Directors and Senior Management.
Directors
The following table sets forth the names and positions of the members of our Board as of the date of this registration statement. The business address of each of the directors is c/o Diversified Energy Company plc, 1600 Corporate Drive, Birmingham, Alabama 35242.
Name
​ ​
Position
​ ​
Director Since(1)
​
Robert Russell (“Rusty”) Hutson, Jr. ​ ​ Co-Founder, Chief Executive Officer and Director ​ ​
July 2014
​
David E. Johnson ​ ​ Independent Chairman of the Board ​ ​
Feb. 2017
​
Martin K. Thomas ​ ​ Vice Chairman of the Board ​ ​
Jan. 2015
​
Kathryn Z. Klaber ​ ​ Independent Director ​ ​
Jan. 2023
​
Sylvia J. Kerrigan ​ ​ Senior Independent Director ​ ​
Oct. 2021
​
Sandra M. Stash ​ ​ Independent Director ​ ​
Oct. 2019
​
David J. Turner, Jr. ​ ​ Independent Director ​ ​
May 2019
​
​
(1)
The executive director’s service agreement is of indefinite duration, subject to termination by the Company or the individual on six months’ notice. The non-executive director serves for an initial period of 12 months, subject to re-election at each annual general meeting of the Company and is terminable on three months’ notice given by either party.
​
Senior Management
The following table sets forth the names and positions of the members of our Senior Management team as of the date of this registration statement. The business address for each member of our Senior Management is c/o Diversified Energy Company plc, 1600 Corporate Drive, Birmingham, Alabama 35242.
Name
​ ​
Position
​
Robert Russell (“Rusty”) Hutson, Jr. ​ ​ Co-Founder, Chief Executive Officer and Director ​
Bradley G. Gray ​ ​ President and Chief Financial Officer ​
Benjamin Sullivan ​ ​ Senior Executive Vice President, Chief Legal & Risk Officer, and Corporate Secretary ​
B.   Advisers.
Our external legal advisers are Latham & Watkins LLP, whose address is 300 Colorado Street, Suite 2400, Austin, Texas 78701, and Latham & Watkins (London) LLP, whose address is 99 Bishopsgate London EC2M 3XF United Kingdom.
C.   Auditors.
PricewaterhouseCoopers LLP has been our statutory auditor since 2020. PricewaterhouseCoopers LLP has audited our financial statements for the periods ended December 31, 2022, 2021 and 2020. PricewaterhouseCoopers LLP is an independent registered public accounting firm, registered with the Public Company Accounting Oversight Board (United States). For more information on our auditors, see “Item 10. Additional Information — G. Statements by Experts.”
Item 2.   Offer Statistics and Expected Timetable
Not applicable.
 
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Item 3.   Key Information
A.   [Reserved.]
B.   Cash and Cash Equivalents, Capitalization and Indebtedness
The table below sets forth our cash and cash equivalents, capitalization and indebtedness as of June 30, 2023, to which no significant updates have occurred through the date of this filing. This table should be read in conjunction with “Item 5. Operating and Financial Review and Prospects,” and the unaudited condensed consolidated interim financial statements and the related notes thereto, which appear elsewhere in this registration statement.
(in thousands)
​ ​ ​ ​ ​ ​ ​
Total debt
​ ​ ​ $ l,555,208 ​ ​
Shareholders’ equity: ​ ​ ​ ​ ​ ​ ​
Ordinary shares, nominal value £0.01 per share:      shares, actual;      shares, as adjusted
​ ​ ​ ​ ​ ​ ​
Share capital
​ ​ ​ ​ 13,056 ​ ​
Share premium account
​ ​ ​ ​ 1,208,192 ​ ​
Treasury reserve
​ ​ ​ ​ (92,811) ​ ​
Share based payment and other reserves
​ ​ ​ ​ 9,620 ​ ​
Retained earnings (accumulated deficit)
​ ​ ​ ​ (590,109) ​ ​
Non-controlling interest
​ ​ ​ ​ 13,050 ​ ​
Total shareholders’ equity
​ ​ ​ ​ 560,998 ​ ​
Total capitalization
​ ​ ​ $ 2,116,206 ​ ​
C.   Reasons for the Offer and Use of Proceeds
Not applicable.
D.   Risk Factors
You should carefully consider the risks described below, together with all of the other information in this registration statement on Form 20-F. The risks and uncertainties below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we believe to be immaterial may also adversely affect our business. If any of the following risks occur, our business, financial condition, and results of operations could be seriously harmed and you could lose all or part of your investment. This registration statement also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including the risks described below and elsewhere in this registration statement.
Summary of Risk Factors
We are subject to a variety of risks and uncertainties which could have a material adverse effect on our business, financial condition, and results of operations. The summary below is not exhaustive and is qualified by reference to the full set of risk factors set forth in this “Risk Factors” section.
•
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.
​
 
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•
The present value of future net cash flows from our reserves, or PV-10, will not necessarily be the same as the current market value of our estimated natural gas, NGL and oil reserves.
​
•
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 COVID-19 pandemic (or another pandemic or epidemic) may have an adverse effect on our business, results of operations, financial condition, cash flows or prospects.
​
•
Deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions could have a material adverse effect on our liquidity, results of operations, business and financial condition that we cannot predict.
​
•
Our operations are subject to a series of risks relating to climate change.
​
•
We rely on third-party infrastructure such as TC Energy (formerly TransCanada), Enbridge, CNX, Dominion Energy Transmission, Enlink, Williams and MarkWest (defined herein) that we do not control and/ or, in each case, are subject to tariff charges that we do not control.
​
•
Failure by us, our contractors or our primary offtakers to obtain access to necessary equipment and transportation systems could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
​
•
A proportion of our equipment has substantial prior use and significant expenditure may be required to maintain operability and operations integrity.
​
•
We depend on our directors, key members of management, independent experts, technical and operational service providers and on our ability to retain and hire such persons to effectively manage our growing business.
​
•
We may face unanticipated water and other waste disposal costs.
​
•
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
​
•
Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability to enter into future debt financing.
​
•
There are risks inherent in our acquisitions of natural gas and oil assets.
​
•
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 permits, licenses, contracts and field development plans.
​
•
Our operations are subject to the risk of litigation.
​
•
The price of our ordinary shares may be volatile and may fluctuate due to factors beyond our control.
​
•
The dual listing of our ordinary shares may adversely affect the liquidity and value of our ordinary shares.
​
 
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•
Failure to comply with requirements to design, implement and maintain effective internal control over financial reporting could have a material adverse effect on our business.
​
•
We are subject to certain tax risks, including changes in tax legislation in the United Kingdom and the United States.
​
Risks Related to Our Business, Operations and Industry
Volatility and future decreases in natural gas, NGLs and oil prices could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
Our business, results of operations, financial condition, cash flows or prospects depend substantially upon prevailing natural gas, NGL and oil prices, which may be adversely impacted by unfavorable global, regional and national macroeconomic conditions, including but not limited to instability related to the military conflict in Ukraine and the COVID-19 pandemic. Natural gas, NGLs and oil are commodities for which prices are determined based on global and regional demand, supply and other factors, all of which are beyond our control.
Historically, prices for natural gas, NGLs and oil have fluctuated widely for many reasons, including:
•
global and regional supply and demand, and expectations regarding future supply and demand, for gas and oil products;
​
•
global and regional economic conditions;
​
•
evolution of stocks of oil and related products;
​
•
increased production due to new extraction developments and improved extraction and production methods;
​
•
geopolitical uncertainty;
​
•
threats or acts of terrorism, war or threat of war, which may affect supply, transportation or demand;
​
•
weather conditions, natural disasters, climate change and environmental incidents;
​
•
access to pipelines, storage platforms, shipping vessels and other means of transporting, storing and refining gas and oil, including without limitation, changes in availability of, and access to, pipeline ullage;
​
•
prices and availability of alternative fuels;
​
•
prices and availability of new technologies affecting energy consumption;
​
•
increasing competition from alternative energy sources;
​
•
the ability of OPEC and other oil-producing nations, to set and maintain specified levels of production and prices;
​
•
political, economic and military developments in gas and oil producing regions generally;
​
•
governmental regulations and actions, including the imposition of export restrictions and taxes and environmental requirements and restrictions as well as anti-hydrocarbon production policies;
​
•
trading activities by market participants and others either seeking to secure access to natural gas, NGLs and oil or to hedge against commercial risks, or as part of an investment portfolio; and
​
•
market uncertainty, including fluctuations in currency exchange rates, and speculative activities by those who buy and sell natural gas, NGLs and oil on the world markets.
​
It is impossible to accurately predict future gas, NGL and oil price movements. Historically, natural gas prices have been highly volatile and subject to large fluctuations in response to relatively minor changes in the demand for natural gas. According to the U.S. Energy Information Administration, the historical high and low Henry Hub natural gas spot prices per MMBtu for the following periods were as follows: in 2020, high
 
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of $3.14 and low of $1.33; in 2021, high of $23.86 and low of $2.43; in 2022, high of $9.85 and low of $3.46, and for the six months ended June 30, 2023, high of $3.78 and low of $1.74 — highlighting the volatile nature of commodity prices.
The economics of producing from some wells and assets may also result in a reduction in the volumes of our reserves which can be produced commercially, resulting in decreases to our reported reserves. Additionally, further reductions in commodity prices may result in a reduction in the volumes of our reserves. We might also elect not to continue production from certain wells at lower prices, or our license partners may not want to continue production regardless of our position.
Each of these factors could result in a material decrease in the value of our reserves, which could lead to a reduction in our natural gas, NGLs and oil development activities and acquisition of additional reserves. In addition, certain development projects or potential future acquisitions could become unprofitable as a result of a decline in price and could result in us postponing or canceling a planned project or potential acquisition, or if it is not possible to cancel, to carry out the project or acquisition with negative economic impacts. Further, a reduction in natural gas, NGL or oil prices may lead our producing fields to be shut down and to be entered into the decommissioning phase earlier than estimated.
Our revenues, cash flows, operating results, profitability, dividends, future rate of growth and the carrying value of our gas and oil properties depend heavily on the prices we receive for natural gas, NGLs and oil sales. Commodity prices also affect our cash flows available for capital investments and other items, including the amount and value of our gas and oil reserves. In addition, we may face gas and oil property impairments if prices fall significantly. In light of the continuing increase in supply coming from the Utica and Marcellus shale plays of the Appalachian Basin, no assurance can be given that commodity prices will remain at levels which enable us to do business profitably or at levels that make it economically viable to produce from certain wells and any material decline in such prices could result in a reduction of our net production volumes and revenue and a decrease in the valuation of our production properties, which could negatively impact our business, results of operations, financial condition, cash flows or prospects.
We conduct our business in a highly competitive industry.
The gas and oil industry is highly competitive. The key areas in which we face competition include:
•
engagement of third-party service providers whose capacity to provide key services may be limited;
​
•
acquisition of other companies that may already own licenses or existing producing assets;
​
•
acquisition of assets offered for sale by other companies;
​
•
access to capital (debt and equity) for financing and operational purposes;
​
•
purchasing, leasing, hiring, chartering or other procuring of equipment that may be scarce; and
​
•
employment of qualified and experienced skilled management and gas and oil professionals and field operations personnel.
​
Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their degree of vertical integration and pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships with the relevant authorities. The cost to attract and retain qualified and experienced personnel has increased and may increase substantially in the future.
Our competitors also include those entities with greater technical, physical and financial resources than us. Finally, companies and certain private equity firms not previously investing in gas and oil may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect us.
The effects of operating in a competitive industry may include:
•
higher than anticipated prices for the acquisition of licenses or assets;
​
 
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•
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.
The levels of our natural gas and oil reserves and resources, their quality and production volumes may be lower than estimated or expected.
The reserves data as of December 31, 2022, 2021 and 2020 contained in this registration statement have been audited by Netherland, Sewell & Associates, Inc. (“NSAI”) unless stated otherwise. The standards
 
10
 
utilized to prepare the reserves information that has been extracted in this document may be different from the standards of reporting adopted in other jurisdictions. Investors, therefore, should not assume that the data found in the reserves information set forth in this registration statement is directly comparable to similar information that has been prepared in accordance with the reserve reporting standards of other jurisdictions, such as the United Kingdom.
In general, estimates of economically recoverable natural gas, NGLs and oil reserves are based on a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological, geophysical and engineering estimates (which have inherent uncertainties), historical production from the properties or analogous reserves, the assumed effects of regulation by governmental agencies and estimates of future commodity prices, operating costs, gathering and transportation costs and production related taxes, all of which may vary considerably from actual results.
Underground accumulations of hydrocarbons cannot be measured in an exact manner and estimates thereof are a subjective process aimed at understanding the statistical probabilities of recovery. Estimates of the quantity of economically recoverable natural gas and oil reserves, rates of production and, where applicable, the timing of development expenditures depend upon several variables and assumptions, including the following:
•
production history compared with production from other comparable producing areas;
​
•
quality and quantity of available data;
​
•
interpretation of the available geological and geophysical data;
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•
effects of regulations adopted by governmental agencies;
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•
future percentages of sales;
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•
future natural gas, NGLs and oil prices;
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•
capital investments;
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•
effectiveness of the applied technologies and equipment;
​
•
effectiveness of our field operations employees to extract the reserves;
​
•
natural events or the negative impacts of natural disasters;
​
•
future operating costs, tax on the extraction of commercial minerals, development costs and workover and remedial costs; and
​
•
the judgment of the persons preparing the estimate.
​
As all reserve estimates are subjective, each of the following items may differ materially from those assumed in estimating reserves:
•
the quantities and qualities that are ultimately recovered;
​
•
the timing of the recovery of natural gas and oil reserves;
​
•
the production and operating costs incurred;
​
•
the amount and timing of development expenditures, to the extent applicable;
​
•
future hydrocarbon sales prices; and
​
•
decommissioning costs and changes to regulatory requirements for decommissioning.
​
Many of the factors in respect of which assumptions are made when estimating reserves are beyond our control and therefore these estimates may prove to be incorrect over time. Evaluations of reserves necessarily involve multiple uncertainties. The accuracy of any reserves evaluation depends on the quality of available information and natural gas, NGLs and oil engineering and geological interpretation. Furthermore, less historical well production data is available for unconventional wells because they have only become technologically viable in the past twenty years and the long-term production data is not always sufficient to determine terminal decline rates. In comparison, some conventional wells in our portfolio have been
 
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productive for a much longer time. As a result, there is a risk that estimates of our shale reserves are not as reliable as estimates of the conventional well reserves that have a longer historical profile to draw on. Interpretation, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserves and resources data. Moreover, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material.
If the assumptions upon which the estimates of our natural gas and oil reserves prove to be incorrect or if the actual reserves available to us (or the operator of an asset in we have an interest) are otherwise less than the current estimates or of lesser quality than expected, we may be unable to recover and produce the estimated levels or quality of natural gas, NGLs or oil set out in this document and this may materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
The PV-10, will not necessarily be the same as the current market value of our estimated natural gas, NGL and oil reserves.
You should not assume that the present value of future net cash flows from our reserves is the current market value of our estimated natural gas, NGL and oil reserves. Actual future net cash flows from our natural gas and oil properties will be affected by factors such as:
•
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, four of our largest wellbore states, setting forth plugging and abandonment schedules spanning a period ranging from 10 to 15 years. We will incur such decommissioning costs at the end of the operating life of some of our properties. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques, the shortage of plugging vendors, difficult terrain or weather conditions or experience at other production sites. The expected timing and amount of expenditure can also change, for example, in response to changes in reserves, wells losing commercial viability sooner than forecasted or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The use of other funds to satisfy such decommissioning costs may impair our ability to focus capital investment in other areas of our business, which could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
We may not be able to keep pace with technological developments in our industry or be able to implement them effectively.
The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies, such as emissions controls and
 
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processing technologies. Rapid technological advancements in information technology and operational technology domains require seamless integration. Failure to integrate these technologies efficiently may result in operational inefficiencies, security vulnerabilities, and increased costs. During mergers and acquisitions, integrating technology assets from acquired companies can be complex. Poor integration may lead to data inconsistencies, security gaps and operational disruptions. Technology systems are also susceptible to cybersecurity threats, including malware, data breaches, and ransomware attacks. These threats may disrupt operations, compromise sensitive data and lead to significant financial losses. Further, inefficient data management practices may result in data breaches, data loss and missed opportunities for operational insights. The presence of legacy technology systems can also pose challenges, as they may lack modern security features, making them vulnerable to cyber threats and necessitating costly upgrades. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, which may in the future allow them to implement new technologies before we can. Additionally, reliance on global supply chains for information technology hardware, software and operational technology equipment exposes the industry to supply chain disruptions, shortages and cybersecurity risks.
A lowering or withdrawal of the ratings, outlook or watch assigned to us or our debt by rating agencies may increase our future borrowing costs and reduce our access to capital.
The rating, outlook or watch assigned to us or our debt could be lowered or withdrawn entirely by a rating agency if, in that rating agency’s judgment, current or future circumstances relating to the basis of the rating, outlook, or watch such as adverse changes to our business, so warrant. Our credit ratings may also change as a result of the differing methodologies or changes in the methodologies used by the rating agencies. Any future lowering of our debt’s ratings, outlook or watch likely would make it more difficult or more expensive for us to obtain additional debt financing.
It is also possible that such ratings may be lowered in connection with this listing or in connection with future events, such as future acquisitions. Holders of our ordinary shares will have no recourse against us or any other parties in the event of a change in or suspension or withdrawal of such ratings. Any lowering, suspension or withdrawal of such ratings may have an adverse effect on the market price or marketability of our ordinary shares.
If we do not have access to capital on favorable terms, on the timeline we require, or at all, our financial condition and results of operations could be materially adversely affected.
We require capital to complete acquisitions that we believe will enhance shareholder return. Significant volatility or disruption in the global financial markets may result in us not being able to obtain additional financing on favorable terms, on the timeline we anticipate, or at all, and we may not be able to refinance, if necessary, any outstanding debt when due, all of which could have a material adverse effect on our financial condition. Any inability to obtain additional funding on favorable terms, on the timeline we anticipate, or at all, may prevent us from acquiring new assets, cause us to curtail our operations significantly, reduce planned capital expenditures or obtain funds through arrangements that management does not currently anticipate, including disposing of our assets, the occurrence of any of which may significantly impair our ability to deliver shareholder returns. If our operating results falter, our cash flow or capital resources prove inadequate, or if interest rates increase significantly, we could face liquidity problems that could materially and adversely affect our results of operations and financial condition.
The COVID-19 pandemic (or another pandemic or epidemic) may have an adverse effect on our business, results of operations, financial condition, cash flows or prospects.
The COVID-19 pandemic has brought considerable change and is expected to continue to bring considerable change to the risk landscape, increasing the impact of many of our principal risks and creating uncertainty in how the future risk landscape will unfold. For example, the impact of the COVID-19 pandemic on commodity pricing in the second quarter of 2020 led to a sharp decline in production of oil from shale players, consequently impacting the production of associated natural gas. We continue to monitor
 
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the evolving COVID-19 pandemic and although our operations have not incurred any significant disruption related to COVID-19, the situation is uncertain and could change in the future.
The extent of the impact of the pandemic on our business, results of operations, financial condition, cash flows or prospects will depend largely on future developments, including operational shutdowns due to the unavailability of qualified personnel, third party utilities or spare parts required to safely maintain operations due to outbreaks of COVID-19 or any future pandemics or epidemics, delayed execution of projects or increased project costs due to governmental restrictions and measures put in place to safeguard employees and contractors, such as reducing personnel and deferring discretionary activities at our assets, which may cause delays in expected future cash flows, all of which are highly uncertain and cannot be predicted. This situation continues to evolve, and additional impacts may arise due to COVID-19, or another pandemic or epidemic, that we are not aware of currently. Any negative impact could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
Deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions could have a material adverse effect on our liquidity, results of operations, business and financial condition that we cannot predict.
Economic conditions in a number of industries in which our customers operate have experienced substantial deterioration in the past, resulting in reduced demand for natural gas and oil. Renewed or continued weakness in the economic conditions of any of the industries we serve or that are served by our customers, or the increased focus by markets on carbon-neutrality, could adversely affect our business, financial condition, results of operation and liquidity in a number of ways. For example:
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demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas business;
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a decrease in international demand for natural gas or NGLs produced in the United States could adversely affect the pricing for such products, which could adversely affect our results of operations and liquidity;
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the tightening of credit or lack of credit availability to our customers could adversely affect our liquidity, as our ability to receive payment for our products sold and delivered depends on the continued creditworthiness of our customers;
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our ability to refinance our Credit Facility may be limited and the terms on which we are able to do so may be less favorable to us depending on the strength of the capital markets or our credit ratings;
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our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our natural gas reserves;
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increased capital markets scrutiny of oil and gas companies may lead to increased costs of capital or lack of credit availability; and
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a decline in our creditworthiness may require us to post letters of credit, cash collateral, or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.
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In addition, the COVID-19 pandemic has materially and adversely impacted many businesses, industries and economies. For further detail regarding the risks to our business resulting from COVID-19, see the Risk Factor below titled “— The COVID-19 pandemic (or another pandemic or epidemic) may have an adverse effect on our business, results of operations, financial condition, cash flows or prospects.”
Our operations are subject to a series of risks relating to climate change.
Continued public concern regarding climate change and potential mitigation through regulation could have a material impact on our business. International agreements, national, regional, state and local legislation, and regulatory measures to limit GHG emissions are currently in place or in various stages of discussion or implementation. For example, the Inflation Reduction Act, which was signed into law in August 2022, includes a “methane fee” that is expected to be imposed beginning with emissions reported for calendar year 2024. In addition, the current U.S. administration has proposed more stringent methane pollution limits
 
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for new and existing gas and oil operations. Given that some of our operations are associated with emissions of GHGs, these and other GHG emissions-related laws, policies and regulations may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted by particular countries, states, provinces and municipalities.
Internationally, the United Nations-sponsored “Paris Agreement” requires member nations to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered in Glasgow at the 26th Conference of the Parties to the UN Framework Convention on Climate Change, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Such commitments were re-affirmed at the 27th Conference of the Parties in Sharm El Sheikh. The emission reduction targets and other provisions of legislative or regulatory initiatives and policies enacted in the future by the United States or states in which we operate, could adversely impact our business by imposing increased costs in the form of higher taxes or increases in the prices of emission allowances, limiting our ability to develop new gas and oil reserves, transport hydrocarbons through pipelines or other methods to market, decreasing the value of our assets, or reducing the demand for hydrocarbons and refined petroleum products. With increased pressure to reduce GHG emissions by replacing fossil fuel energy generation with alternative energy generation, it is possible that peak demand for gas and oil will be reached, and gas and oil prices will be adversely impacted as and when this happens. Further, the consequences of the effects of global climate change, and the continued political and societal attention afforded to mitigating the effects of climate change, may generate adverse investor and stakeholder sentiment towards the hydrocarbon industry and negatively impact the ability to invest in the sector. Similarly, longer term reduction in the demand for hydrocarbon products due to the pace of commercial deployment of alternative energy technologies or due to shifts in consumer preference for lower GHG emissions products could reduce the demand for the hydrocarbons that we produce.
Additionally, the SEC’s proposed climate rule published in March 2022, requiring disclosure of a range of climate related risks, is expected to be finalized late-2023. We are currently assessing this rule, and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. Additionally, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.
Further, in response to concerns related to climate change, companies in the fossil fuel sector may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to sustainable lending practices, and some of them may elect in the future not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In 2021, President Biden signed an executive order calling for the development of a “climate finance plan,” and, separately, the Federal Reserve announced in 2020 that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, and transportation activities, which could in turn negatively affect our operations.
The Company may also be subject to activism from environmental non-governmental organizations (“NGOs”) campaigning against fossil fuel extraction or negative publicity from media alleging inadequate remedial actions to retire non-producing wells effectively, which could affect our reputation, disrupt our programs, require us to incur significant, unplanned expense to respond or react to intentionally disruptive
 
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campaigns or media reports, create blockades to interfere with operations or otherwise negatively impact our business, results of operations, financial condition, cash flows or prospects. Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
Finally, our operations are subject to disruption from the physical effects that may be caused or aggravated by climate change. These include risks from extreme weather events, such as hurricanes, severe storms, floods, heat waves, and ambient temperature increases, as well as wildfires, each of which may become more frequent or more severe as a result of climate change.
We rely on third-party infrastructure that we do not control and/or, in each case, are subject to tariff charges that we do not control.
A significant portion of our production passes through third-party owned and controlled infrastructure. If these third-party pipelines or liquids processing facilities experience any event that causes an interruption in operations or a shut-down such as mechanical problems, an explosion, adverse weather conditions, a terrorist attack or labor dispute, our ability to produce or transport natural gas could be severely affected. For example, we have an agreement with a third-party where approximately 51% of the NGLs we sold during the year ending December 31, 2022 were processed at the third-party’s facility in Kentucky. Any material decrease in our ability to process or transport our natural gas through third-party infrastructure could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
Our use of third-party infrastructure may be subject to tariff charges. Although we seek to manage our flow via our midstream infrastructure, we may not always be able to avoid higher tariffs or basis blowouts due to the lack of interconnections. In such instances, the tariff charges can be substantial and the cost is not subject to our direct control, although we may have certain contractual or governmental protections and rights. Generally, the operator of the gathering or transmission pipelines sets these tariffs and expenses on a cost sharing basis according to our proportionate hydrocarbon through-put of that facility. A provisional tariff rate is applied during the relevant year and then finalized the following year based on the actual final costs and final through-put volumes. Such tariffs are dependent on continued production from assets owned by third parties and, may be priced at such a level as to lead to production from our assets ceasing to be economic and thus may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
Furthermore, our use of third-party infrastructure exposes us to the possibility that such infrastructure will cease to be operational or be decommissioned and therefore require us to source alternative export routes and/or prevent economic production from our assets. This could also have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
Failure by us, our contractors or our primary offtakers to obtain access to necessary equipment and transportation systems could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
We rely on our natural gas and oil field suppliers and contractors to provide materials and services that facilitate our production activities, including plugging and abandonment contractors. Any competitive pressures on the oil field suppliers and contractors could result in a material increase of costs for the materials and services required to conduct our business and operations. For example, we are dependent on the availability of plugging vendors to help us satisfy abandonment schedules that we have agreed to with the states of Ohio, West Virginia, Kentucky and Pennsylvania. Such personnel and services can be scarce and may not be readily available at the times and places required. Future cost increases could have a material adverse effect on our asset retirement liability, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of our properties, our planned level of spending for development and the level of our reserves. Prices for the materials and services we depend on to conduct our business may not be sustained at levels that enable us to operate profitably.
 
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We and our offtakers rely, and any future offtakers will rely, upon the availability of pipeline and storage capacity systems, including such infrastructure systems that are owned and operated by third parties. As a result, we may be unable to access or source alternatives for the infrastructure and systems which we currently use or plan to use, or otherwise be subject to interruptions or delays in the availability of infrastructure and systems necessary for the delivery of our natural gas, NGLs and oil to commercial markets. In addition, such infrastructure may be close to its design life and decisions may be taken to decommission such infrastructure or perform life extension work to maintain continued operations. Any of these events could result in disruptions to our projects and thereby impact our ability to deliver natural gas, NGLs and oil to commercial markets and/or may increase our costs associated with the production of natural gas, NGLs and oil reliant upon such infrastructure and systems. Further, our offtakers could become subject to increased tariffs imposed by government regulators or the third-party operators or owners of the transportation systems available for the transport of our natural gas, NGLs and oil, which could result in decreased offtaker demand and downward pricing pressure.
If we are unable to access infrastructure systems facilitating the delivery of our natural gas, NGLs and oil to commercial markets due to our contractors or primary offtakers being unable to access the necessary equipment or transportation systems, our operations will be adversely affected. If we are unable to source the most efficient and expedient infrastructure systems for our assets then delivery of our natural gas, NGLs and oil to the commercial markets may be negatively impacted, as may our costs associated with the production of natural gas, NGLs and oil reliant upon such infrastructure and systems.
A proportion of our equipment has substantial prior use and significant expenditure may be required to maintain operability and operations integrity.
A part of our business strategy is to optimize or refurbish producing assets where possible to maximize the efficiency of our operations while avoiding significant expenses associated with purchasing new equipment. Our producing assets and midstream infrastructure require ongoing maintenance to ensure continued operational integrity. For example, some older wells may struggle to produce suitable line pressure and will require the addition of compression to push natural gas. Despite our planned operating and capital expenditures, there can be no guarantee that our assets or the assets we use will continue to operate without fault and not suffer material damage in this period through, for example, wear and tear, severe weather conditions, natural disasters or industrial accidents. If our assets, or the assets we use, do not operate at or above expected efficiencies, we may be required to make substantial expenditures beyond the amounts budgeted. Any material damage to these assets or significant capital expenditure on these assets for improvement or maintenance may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects. In addition, as with planned operating and capital expenditure, there is no guarantee that the amounts expended will ensure continued operation without fault or address the effects of wear and tear, severe weather conditions, natural disasters or industrial accidents. We cannot guarantee that such optimization or refurbishment will be commercially feasible to undertake in the future and we cannot provide assurance that we will not face unexpected costs during the optimization or refurbishment process.
We depend on our directors, key members of management, independent experts, technical and operational service providers and on our ability to retain and hire such persons to effectively manage our growing business.
Our future operating results depend in significant part upon the continued contribution of our directors, key senior management and technical, financial and operations personnel. Management of our growth will require, among other things, stringent control of financial systems and operations, the continued development of our control environment, the ability to attract and retain sufficient numbers of qualified management and other personnel, the continued training of such personnel and the presence of adequate supervision.
In addition, the personal connections and relationships of our directors and key management are important to the conduct of our business. If we were to unexpectedly lose a member of our key management or fail to maintain one of the strategic relationships of our key management team, our business, results of operations, financial condition, cash flows or prospects could be materially adversely affected. In particular, we are highly dependent on our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr. Acquisitions
 
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are a key part of our strategy, and Mr. Hutson has been instrumental in sourcing them and securing their financing. Furthermore, as our founder, Mr. Hutson is strongly associated with our success, and if he were to cease being the Chief Executive Officer, perception of our future prospects may be diminished. We maintain a “key person” life insurance policy on Mr. Hutson, but not any other of our employees. As a result, we are insured against certain losses resulting from the death of Mr. Hutson, but not any of our other employees.
Attracting and retaining additional skilled personnel will be fundamental to the continued growth and operation of our business. We require skilled personnel in the areas of development, operations, engineering, business development, natural gas, NGLs and oil marketing, finance and accounting relating to our projects. Personnel costs, including salaries, are increasing as industry wide demand for suitably qualified personnel increases. We may not successfully attract new personnel and retain existing personnel required to continue to expand our business and to successfully execute and implement our business strategy.
We may face unanticipated water and other waste disposal costs.
We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas, oil and NGL production operations. Productive zones frequently contain water that must be removed for the natural gas, oil and NGL to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas, oil and NGL in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. We have entered into various water management services agreements in the Appalachian Basin which provide for the disposal of our produced water by established counterparties with large integrated pipeline networks. If these counterparties fail to perform, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase for a number of reasons, including if new laws and regulations require water to be disposed in a different manner.
In 2016, the EPA adopted effluent limitations for the treatment and discharge of wastewater resulting from onshore unconventional natural gas, oil and NGL extraction facilities to publicly owned treatment works. In addition, the injection of fluids gathered from natural gas, oil and NGL producing operations in underground disposal wells has been identified by some groups and regulators as a potential cause of increased seismic events in certain areas of the country, including the states of West Virginia, Ohio and Kentucky in the Appalachian Basin as well as Oklahoma, Texas and Louisiana in our Central Region. Certain states, including those located in the Appalachian Basin have adopted, or are considering adopting, laws and regulations that may restrict or prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic events have occurred to restrict or suspend disposal well permits or operations or impose certain conditions related to disposal well construction, monitoring, or operations. Any of these developments could increase our cost to dispose of our produced water.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to the authority under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), as amended by the Pipeline Safety Improvement Act of 2002 (“PSIA”), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPESA”) and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact HCAs;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
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In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of pipeline integrity testing, but the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the safe and reliable operation of our pipelines.
The 2011 Pipeline Safety Act amends the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. Additionally, pursuant to one of the requirements of the 2011 Pipeline Safety Act, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain gas lines, extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond HCAs to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as five dwellings within the potential impact area and require gas pipelines installed before 1970 that were exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”). Other requirements proposed by PHMSA under the rulemaking include: reporting to PHMSA in the event of certain MAOP exceedances; strengthening PHMSA integrity management requirements; considering seismicity in evaluating threats to a pipeline; conducting hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and using more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on gathering lines. In January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to an HCA. The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure PHMSA regularly revises its pipeline safety regulations. For example, in June 2016, the President signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “2016 PIPES Act”) into law. The 2016 PIPES Act reauthorizes PHMSA through 2019, and facilitates greater pipeline safety by providing PHMSA with emergency order authority, including authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazards, without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses. The 2016 PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from the 2011 Pipeline Safety Act PHMSA has recently published three parts of its so-called “Mega Rule,” including rules focused on: the safety of gas transmission pipelines, the safety of hazardous liquid pipelines and enhanced emergency order procedures. PHMSA finalized the first part of the rule, which primarily addressed maximum operating pressure and integrity management near HCAs for onshore gas transmission pipelines, in October 2019. PHMSA finalized the second part of the rule, which extended federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures, in November 2021. PHMSA published the final of the three components of the Mega Rule in August 2022, which took effect in May 2023. The final rule applies to onshore gas transmission pipelines, and
 
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clarifies integrity management regulations, expands corrosion control requirements, mandates inspection after extreme weather events, and updates existing repair criteria for both HCA and non-HCA pipelines. Finally, PHMSA published a Notice of Proposed Rulemaking regarding more stringent gas pipeline leak detection and repair requirements to reduce natural gas emissions on May 18, 2023.
At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
Moreover as of January 2023, the maximum civil penalties PHMSA can impose are $257,664 per pipeline safety violation per day, with a maximum of $2,576,627 for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA regulations thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. States are also pursuing regulatory programs intended to safely build pipeline infrastructure. The adoption of new or amended regulations by PHMSA or the states that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on us and similarly situated midstream operators.
We are currently operating in a period of economic uncertainty and capital markets disruption, which has been significantly impacted by geopolitical instability due to the ongoing military conflict between Russia and Ukraine, and more recently, the Israel-Hamas war. Our business may be adversely affected by any negative impact on the global economy and capital markets resulting from the conflict in Ukraine or any other geopolitical tensions.
U.S. and global markets are experiencing volatility and disruption following the escalation of geopolitical tensions and the start of the military conflict between Russia and Ukraine. In February 2022, a full-scale military invasion of Ukraine by Russian troops was reported. Although the length and impact of the ongoing military conflict is highly unpredictable, the conflict in Ukraine has led, and could continue to lead, to market disruptions, including significant volatility in commodity prices, credit and capital markets, as well as supply chain interruptions.
Additionally, Russia’s prior annexation of Crimea, recent recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsequent military interventions in Ukraine have led to sanctions and other penalties being levied by the United States, European Union and other countries against Russia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic, and the so-called Luhansk People’s Republic, including agreement to remove certain Russian financial institutions from the Society for Worldwide Interbank Financial Telecommunication (“SWIFT”) payment system, expansive bans on imports and exports of products to and from Russia and bans on the exportation of U.S. denominated banknotes to Russia or persons located there. Additional potential sanctions and penalties have also been proposed and/or threatened. Russian military actions and the resulting sanctions could adversely affect the global economy and financial markets and lead to instability and lack of liquidity in capital markets, potentially making it more difficult for us to obtain additional funds.
Additionally, on October 7, 2023, Hamas, a U.S. designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel. On October 8, 2023, Israel formally declared war on Hamas, and the armed conflict is ongoing as of the date of this filing. Hostilities between Israel and Hamas could escalate and involve surrounding countries in the Middle East. We are actively monitoring the situation in Ukraine and Israel and assessing their impact on our business. To date we have not experienced any material interruptions in our infrastructure, supplies, technology systems or networks needed to support our operations given our operating areas are exclusively located within the Central Region and the Appalachian Basins of the U.S. We have no way to predict the progress or outcome of the conflicts in Ukraine or Israel or their impacts in Ukraine, Russia, Belarus, Israel or the Gaza Strip as the conflicts, and any resulting government reactions, are rapidly developing and beyond our control. The extent and duration of the military actions, sanctions and resulting market disruptions could be significant and could potentially
 
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have substantial impact on the global economy and our business for an unknown period of time. Any of the aforementioned factors could affect our business, financial condition and results of operations. Any such disruptions may also magnify the impact of other risks described in this registration statement.
Risks Relating to our Financing, Acquisitions, Investment and Indebtedness
Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability to enter into future debt financing.
Inflation can adversely affect us by increasing costs of materials, equipment, labor and other services. In addition, inflation is often accompanied by higher interest rates. Continued inflationary pressures could impact our profitability. Though we believe that the rates of inflation in recent years, including the 12 months ended June 30, 2023, have not had a significant impact on our operations, a continued increase in inflation, including inflationary pressure on labor, could result in increases to our operating costs, and we may be unable to pass these costs on to our customers. These inflationary pressures could also adversely impact our ability to procure materials and equipment in a cost-effective manner, which could result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected. We continue to undertake actions and implement plans to address these inflationary pressures and protect the requisite access to materials and equipment. With respect to our costs of capital, our ABS Notes (as defined below) are fixed-rate instruments (subject to adjustment pursuant to the sustainability-linked features described under “Item 5.B Liquidity and Capital Resources”) and as of June 30, 2023 we had $265 million outstanding on our Credit Facility. Nevertheless, inflation may also affect our ability to enter into future debt financing, including refinancing of our Credit Facility or issuing additional SPV-level asset backed securities, as high inflation may result in a relative increase in the cost of debt capital.
We are taking efforts to mitigate inflationary pressures, by working closely with other suppliers and service providers to ensure procurement of materials and equipment in a cost-effective manner. However, these mitigation efforts may not succeed or may be insufficient.
Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which natural gas, NGLs and oil can be sold, which could affect our results of operations, financial condition, cash flows and prospects.
There are risks inherent in our acquisitions of natural gas and oil assets.
Acquisitions are an essential part of our strategy for protecting and growing cash flow, particularly in relation to the risk that some of our wells may have a higher than anticipated production decline rate. Over the past several years, we have undertaken a number of acquisitions of natural gas and oil assets (and of companies holding such assets), including, but not limited to the acquisition of certain assets of Carbon Energy Corporation (the “Carbon Acquisition”), the acquisition of certain assets and infrastructure of EQT Corporation (the “EQT Acquisition”), the acquisition of certain assets from Triad Hunter, LLC (the “Utica Acquisition”), the acquisition of 51.25% working interest in certain assets and infrastructure from Indigo Minerals LLC (the “Indigo Acquisition”), the acquisition of certain assets and infrastructure from Blackbeard Operating LLC (the “Blackbeard Acquisition”), the acquisition of 51.25% working interest in certain assets, infrastructure, equipment and facilities in conjunction with Oaktree from Tanos Energy Holdings III, LLC (the “Tanos Acquisition”), the acquisition of 51.25% working interest in certain assets, infrastructure, equipment and facilities in conjunction with Oaktree from Tapstone Energy Holdings LLC (the “Tapstone Acquisition”), the acquisition of 52.5% working interest in certain upstream assets and related facilities within the Central Region from a private seller, in conjunction with Oaktree (the “East Texas Assets Acquisition”), the acquisition of certain upstream assets and related infrastructure within the Central Region from Tanos Energy Holdings II LLC (the “Tanos II Acquisition”) and the acquisition of certain upstream assets and related gathering infrastructure in the Central Region from ConocoPhillips (the “Conoco Acquisition”). Our ability to complete future acquisitions will depend on us being able to identify suitable acquisition candidates and negotiate favorable terms for their acquisition, in each case,
 
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before any attractive candidates are purchased by other parties such as private equity firms, some of whom have substantially greater financial and other resources than we do. We may face competition for attractive acquisition targets that may also increase the price of the target business. As a result, there is no assurance that we will always be able to source and execute acquisitions in the future at attractive valuations.
Furthermore, to further the Company’s growth, we have made further acquisitions outside the Appalachian Basin, a region in which we have developed our operational experience into the Bossier Shale, the Haynesville Shale, the Barnett Shale Play, and the Cotton Valley and Mid-Continent producing areas. Accordingly, an acquisition in a new area in which we lack experience may present unanticipated risks and challenges that were not accounted for or previously experienced. Ordinarily, our due diligence efforts are focused on higher valued and material properties or assets. Even an in-depth review of all properties and records may not reveal all existing or potential problems, nor will such review always permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Generally, physical inspections are not performed on every well or facility, and structural or environmental problems are not necessarily observable even when an inspection is undertaken.
There can be no assurance that our prior acquisitions or any other potential acquisition will perform operationally as anticipated or be profitable. We could fail to appropriately value any acquired business and the value of any business, company or property that we acquire or invest in may actually be less than the amount paid for it or its estimated production capacity. We may be required to assume pre-closing liabilities with respect to an acquisition, including known and unknown title, contractual, and environmental and decommissioning liabilities, and may acquire interests in properties on an “as is” basis without recourse to the seller of such interest or the seller may have limited resources to provide post-sale indemnities.
In addition, successful acquisitions of gas and oil assets require an assessment of a number of factors, including estimates of recoverable reserves, the time of recovering reserves, exploration potential, future natural gas, NGLs and oil prices and operating costs. Such assessments are inexact, and we cannot guarantee that we make these assessments with a high degree of accuracy. In connection with assessments, we perform a review of the acquired assets. However, such a review will not reveal all existing or potential problems. Furthermore, review may not permit us to become sufficiently familiar with the assets to fully assess their deficiencies and capabilities.
Integrating operations, technology, systems, management, back office personnel and pre- or post-completion costs for future acquisitions may prove more difficult or expensive than anticipated, thereby rendering the value of any company or assets acquired less than the amount paid. We may also take on unexpected liabilities which are uncapped, have to undertake unanticipated capital expenditures in connection with a new acquisition or provide uncapped liabilities in connection with the purchase and sale of assets, which are customary in such agreements. The integration of acquired businesses or assets requires significant time and effort on the part of our management. Following such integration efforts, prior acquisitions may still not achieve the level of financial or operational performance that was anticipated when they were acquired. In addition, the integration of new acquisitions can be difficult and disrupt our own business because our operational and business culture may differ from the cultures of the acquired businesses, unpopular cost-cutting measures may be required, internal controls may be more difficult to maintain and control over cash flows and expenditures may be difficult to establish. If we encounter any of the foregoing issues in relation to one of our acquisitions this could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of businesses that complement or expand our current business. However, we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.
 
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In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
Our Credit Facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
We may not have good title to all our assets and licenses.
Although we believe that we take due care and conduct due diligence on new acquisitions in a manner that is consistent with industry practice, there can be no assurance that we have good title to all our assets and the rights to develop and produce natural gas and oil from our assets. Such reviews are inherently incomplete and it is generally not feasible to review in depth every individual well or field involved in each acquisition. There can be no assurance that any due diligence carried out by us or by third parties on our behalf in connection with any assets that we acquire will reveal all of the risks associated with those assets, and the assets may be subject to preferential purchase rights, consents and title defects that were not apparent at the time of acquisition. We may acquire interests in properties on an “as is” basis without recourse to the seller of such interest or the seller may have limited resources to provide post-sale indemnities. In addition, changes in law or change in the interpretation of law or political events may arise to defeat or impair our claim to certain properties which we currently own or may acquire which could result in a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
The issuance of additional ordinary shares in the Company in connection with future acquisitions or other growth opportunities, any share incentive or share option plan or otherwise may dilute all other shareholdings.
We may seek to raise financing to fund future acquisitions and other growth opportunities. We may, for these and other purposes, issue additional equity or convertible equity securities. As a result, existing holders of ordinary shares may suffer dilution in their percentage ownership or the market price of the ordinary shares may be adversely affected.
As of June 30, 2023, we have issued options under our equity incentive plans to employees and executive directors for a total of 4,784,274 new ordinary shares of the Company, all of which are currently outstanding, and have also entered into restricted stock unit agreements and performance stock unit agreements with certain employees, of which 9,361,961 restricted stock units and 16,294,943 performance stock units are outstanding. We may, in the future, issue further options and/or warrants to subscribe for new ordinary shares to certain advisers, employees, directors, senior management and/or consultants of the Company. The exercise of any such options would result in a dilution of the shareholdings of other investors. Additionally, although we currently have no plans for an offering of ordinary shares, it is possible that we may decide to offer additional ordinary shares in the future. Subject to any applicable pre-emption rights, any future issues of ordinary shares by the Company may have a dilutive effect on the holdings of shareholders and could have a material adverse effect on the market price of ordinary shares as a whole.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our Credit Facility contains a number of significant covenants that may limit our ability to, among other things:
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incur additional indebtedness;
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incur liens;
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sell assets;
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make certain debt payments;
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enter into agreements that restrict or prohibit the payment of dividends;
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limits our subsidiaries’ ability to make certain payments with respect to their equity, based on the pro forma effect thereof on certain financial ratios, which would be the source of distributable profits from which we may issue a dividend; and
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conduct hedging activities.
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In addition, our Credit Facility requires us to maintain compliance with certain financial covenants.
We may also be prevented from taking advantage of business opportunities that arise because of the limitations from the restrictive covenants under our Credit Facility. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities.
A breach of any covenant in our Credit Facility will result in a default under the agreement and may result in an event of default under the Credit Facility if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under our Credit Facility and in an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
Any significant reduction in our borrowing base under our Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Our Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, unilaterally determine based upon our reserve reports for the applicable period and other data and reports. Such determinations will be made on a regular basis semi-annually (each a “Scheduled Redetermination”) and at the option of the lenders with more than 66.6% of the loans and commitments under the Credit Facility, no more than one time in between each Scheduled Redetermination. As of the date hereof, our borrowing base is $425 million.
In the future, we may not be able to access adequate funding under our Credit Facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a borrowing base redetermination, or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender’s portion. Declines in commodity prices from their current levels could result in a determination to lower the borrowing base and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to make acquisitions or otherwise carry out business plans, which could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
The securitizations of our limited purpose, bankruptcy-remote, wholly owned subsidiaries may expose us to financing and other risks, and there can be no assurance that we will be able to access the securitization market in the future, which may require us to seek more costly financing.
Through limited purpose, bankruptcy-remote, wholly owned subsidiaries (“SPVs”), we have securitized and expect to securitize in the future, certain of our assets to generate financing. In such transactions, we convey a pool of assets to an SPV, that, in turn, issues certain securities or enters into certain debt agreements, such as our Term Loan I. The securities issued by the SPVs and the Term Loan I are each collateralized by a pool of assets. In exchange for the transfer of finance receivables to the SPV, we typically receive the cash proceeds from the sale of the securities or entering into term loans.
Although our SPVs have successfully completed securitizations in connection with the Term Loan I, the ABS I Notes, ABS II Notes, ABS III Notes, ABS IV Notes, ABS V Notes and ABS VI Notes (each as defined herein), there can be no assurance that we, through our SPVs, will be able to complete additional securitizations, particularly if the securitization markets become constrained. In addition, the value of any securities that our limited purpose, bankruptcy-remote, wholly owned subsidiaries retain in our
 
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securitizations, including securities retained to comply with applicable risk retention rules, might be reduced or, in some cases, eliminated as a result of an adverse change in economic conditions or the financial markets. In addition, our Term Loan I, ABS I Notes, ABS II Notes, ABS III Notes, ABS IV Notes, ABS V Notes and ABS VI Notes are subject to customary accelerated amortization events, including events tied to the failure to maintain stated debt service coverage ratios.
If it is not possible or economical for us to securitize our assets in the future, we would need to seek alternative financing to support our operations and to meet our existing debt obligations, which may be less efficient and more expensive than raising capital via securitizations and may have a material adverse effect on our results of operations, financial condition, cash flows and liquidity.
An increase in interest rates would increase the cost of servicing our indebtedness and could reduce our profitability, decrease our liquidity and impact our solvency.
Our Credit Facility provides for, and our future debt agreements may provide for, debt incurred thereunder to bear interest at variable rates. As of June 30, 2023, we had $265 million outstanding on our Credit Facility. Increases in interest rates would increase the cost of servicing indebtedness under our Credit Facility or under future debt agreements subject to interest at variable rates, and materially reduce our profitability, decrease our liquidity and impact our solvency. As of October 31, 2023, we had $313 million outstanding on our Credit Facility.
Our hedging activities could result in financial losses or could reduce our net income.
To achieve more predictable cash flows, we employ a hedging strategy involving opportunistically hedging a majority of our first two years of production as well as hedging a significant percentage of production beyond our first two years of forecasted production. Even so, the remainder of our production that is unhedged is exposed to the continuing and prolonged declines in the prices of natural gas, NGLs and oil. Our results of operations and financial condition would be negatively impacted if the prices of natural gas, NGLs or oil were to remain depressed or decline materially from current levels. To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of natural gas, NGLS and oil, we may enter into additional hedging arrangements for a significant portion of our production.
Our derivative contracts may result in substantial gains or losses. For example, we reported an operating loss of $671 million for the year ended December 31, 2022, compared with an operating loss of $467 million for the year ended December 31, 2021. While our earnings are impacted by a variety of factors as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” a key driver of our year over year increase in operating loss was attributable to an increase of $209 million in the mark-to-market valuation adjustment on our derivative financial instrument valuations to $861 million in 2022 from $652 million in 2021. There can be no assurance that we will not realize additional losses due to our hedging activities in the future. In addition, if we enter into any derivative contracts and experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Our ability to use hedging transactions to protect us from future natural gas, NGL and oil price volatility will be dependent upon natural gas, NGL and oil prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes. In addition, if commodity prices remain low, we will not be able to replace our hedges or enter into new hedges at favorable prices.
Our price hedging strategy and future hedging transactions will be determined at our discretion, subject to the terms of certain agreements governing our indebtedness. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our natural gas, NGL and oil revenues becoming more sensitive to commodity price fluctuations.
 
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The failure of our hedge counterparties to meet their obligations to us may adversely affect our financial results.
An attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by the counterparty to these derivative contracts when they become due would have a material adverse effect on our results of operations, financial condition, cash flows and prospects.
We may not be able to enter into commodity derivatives on favorable terms or at all.
To achieve a more predictable cash flow, we employ a hedging strategy involving opportunistically hedging a majority of our first two years of production as well as hedging a significant percentage of production beyond our first two years of forecasted production. If we are unable to maintain sufficient hedging capacity with our counterparties, we could have greater exposure to changes in commodity prices and interest rates, which could have a material adverse impact on our business, results of operations, financial condition, cash flows or prospects.
Risks Relating to Legal, Tax, Environmental and Regulatory Matters
We are subject to regulation and liability under environmental, health and safety regulations, the violation of which may affect our financial condition and operations.
We operate in an industry that has certain inherent hazards and risks, and consequently we are subject to stringent and comprehensive laws and regulations, especially with regard to the protection of health, safety and the environment. For example, we are subject to laws and regulations related to occupational safety and health, hydraulic fracturing activities, air emissions, soil and water quality, the protection of threatened and endangered plant and animal species, biodiversity and ecosystems, and the safety of our assets and employees. Although we believe that we have adequate procedures in place to mitigate operational risks, there can be no assurances that these procedures will be adequate to address every potential health, safety and environmental hazard, and a failure to adequately mitigate risks may result in loss of life, injury, or adverse impacts on the health of employees, contractors and third-parties or the environment. Any failure by us or one of our subcontractors, whether inadvertent or otherwise, to comply with applicable legal or regulatory requirements may give rise to civil, administrative and/or criminal liabilities, civil fines and penalties, delays or restrictions in acquiring or disposing of assets and/or delays in securing or maintaining required permits, licenses and approvals. Further, a lack of regulatory compliance may lead to denial, suspension, or termination of permits, licenses, or approvals that are required to operate our sites or could result in other operational restrictions or obligations. Our health, safety and environmental policies require us to observe local, state and national legal and regulatory requirements and to apply generally accepted industry best practices where legislation or regulation does not exist.
The terms and conditions of licenses, permits, regulatory orders, approvals or permissions may include more stringent operational, environmental and/or health and safety requirements. Obtaining development or production licenses and permits may become more difficult or may be delayed due to federal, regional, state or local governmental constraints, considerations, or requirements on issuing. Furthermore, third-parties such as environmental NGOs may administratively or judicially contest or protest licenses and permits already granted by relevant authorities or applications for the same and operations may be subject to other administrative or judicial challenges.
In addition, under certain environmental laws and regulations, we could be subject to joint and several strict liability for the removal or remediation of previously released materials, pollution, or property contamination regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties on or adjacent to well sites and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property
 
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damage. In addition, the risk of accidental spills or releases of pollutants or contaminants could expose us to significant liabilities that could have a material adverse effect on our business, financial condition and results of operations.
We incur, and expect to continue to incur, capital and operating costs in an effort to comply with increasingly complex operational health and safety and environmental laws and regulations. New laws and regulations, the imposition of more stringent requirements in permits and licenses, increasingly strict enforcement of, or new interpretations of, existing laws, regulations and permits and licenses, or the discovery of previously unknown contamination or hazards may require further costly expenditures to, for example:
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modify operations, including an increase in plugging and abandonment operations;
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install or upgrade pollution or emissions control equipment;
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perform site clean ups, including the remediation and reclamation of gas and oil sites;
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curtail or cease certain operations;
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provide financial securities, bonds, and/or take out insurance; or
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pay fees or fines or make other payments for pollution, discharges to the environment or other breaches of environmental or health and safety requirements or consent agreements with regulatory agencies.
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We cannot predict with any certainty the full impact of any new laws, regulations, or policies on our operations or on the cost or availability of insurance to cover the risks associated with such operations. The costs of such measures and liabilities related to potential operational health and safety or environmental risks associated with the Company may increase, which could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects. In addition, it is not possible to predict what future operational health and safety or environmental laws and regulations will be enacted or how current or future operational, health, safety or environmental laws and regulations will be applied or enforced. We may have to incur significant expenditure for the installation and operation of additional systems and equipment for monitoring and carry out remedial measures in the event that operational health and, safety and environmental regulations become more stringent or costly reform is implemented by regulators. Any such expenditure may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects. No assurance can be given that compliance with occupational health and safety and environmental laws or regulations in the regions where we operate will not result in a curtailment of production or a material increase in the cost of production or development activities.
Increasing attention to ESG matters may impact our business and financial results.
Increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ board of directors and promoting the use of alternative forms of energy. These activities may result in demand shifts for oil and natural gas products and additional governmental investigations and private ligation against us. In addition, a failure to comply with evolving investor or customer expectations and standards or if we are perceived to not have responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operation.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other companies or industries, which could have a negative impact on our stock price and our
 
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access to and costs of capital. Also, institutional lenders may decide not to provide funding for oil and natural gas companies based on climate change related concerns, which could affect our access to capital for potential growth projects.
The current U.S. administration, acting through the executive branch and/or in coordination with Congress, could enact rules and regulations that impose more onerous permitting and other costly environmental, health and safety requirements on our operations.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change-related commitments expressed by some political candidates who are now, or may in the future be, in political office.
While our operations are largely not conducted on federal lands, we may in the future consider acquisitions of natural gas and oil assets located in areas in which the development of such assets would require permits and authorizations to be obtained from or issued by federal agencies. To conduct these operations, we may be required to file applications for permits, seek agency authorizations and comply with various other statutory and regulatory requirements. Further, new oil and gas leasing on public lands has been the subject of recent proposed reforms, including bans in certain areas, raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases. Complying with any of these requirements may adversely affect our ability to conduct operations at the costs and in the time periods anticipated, and may consequently adversely impact our anticipated returns from our operations.
Presidential or congressional actions could adversely affect our operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements. Any such measures or increased costs could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
Our operations are dependent on our compliance with obligations under permits, licenses, contracts and field development plans.
Our operations must be carried out in accordance with the terms of permits, licenses, operating agreements, annual work programs and budgets. Fines, penalties, or enforcement actions may be imposed and a permit or license may be suspended or terminated if a permit or license holder, or party to a related agreement, fails to comply with its obligations under such permit, license or agreement, or fails to make timely payments of levies and taxes for the licensed activity, or fails to provide the required geological information or meet other reporting requirements. It may from time to time be difficult to ascertain whether we have complied with obligations under permits or licenses as the extent of such obligations may be unclear or ambiguous and regulatory authorities in jurisdictions in which we do business, or in which we may do business in the future, may not be forthcoming with confirmatory statements that work obligations have been fulfilled, which can lead to further operational uncertainty.
In addition, we and our commercial partners, as applicable, have obligations to operate assets in accordance with specific requirements under certain licenses and related agreements, field development agreements, laws and regulations. If we or our partners were to fail to satisfy such obligations with respect to a specific field, the license or related agreements for that field may be suspended, revoked or terminated. Although we have in the past acquired and may in the future acquire shale assets, a significant source of our natural gas and crude oil remains conventional wells. In some instances, these conventional wells are located on the same property as unconventional wells that produce shale oil. In these cases, the rights to access the shale layers of the property will typically be conditioned on the ongoing productivity of conventional wells on the property. Furthermore, the shale rights may be owned by a third party, and in such instances, we will enter into a joint use agreement with the third party. This joint use agreement may stipulate that in consideration for permission to operate the conventional wells, we are to use reasonable efforts to maintain production so that the third party retains the shale licenses. If we fail to maintain production in the conventional wells, under the joint use agreement, we may be liable to the third party for replacing the lost land rights. The relevant authorities are typically authorized to, and do from time to time, inspect to verify compliance by us or our commercial partners, as applicable, with relevant laws and the licenses or the agreements pursuant to which we conduct our business. There can be no assurance that the views of the
 
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relevant government agencies regarding the development of the fields that we operate or the compliance with the terms of the licenses pursuant to which we conduct such operations will coincide with our views, which might lead to disagreements that may not be resolved.
The suspension, revocation, withdrawal or termination of any of the permits, licenses or related agreements pursuant to which we may conduct business, as well as any delays in the continuous development of or production at our fields caused by the issues detailed above could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects. In addition, failure to comply with the obligations under the permits, licenses or agreements pursuant to which we conduct business, whether inadvertent or otherwise, may lead to fines, penalties, restrictions, enforcement actions brought by governmental authorities, withdrawal of licenses and termination of related agreements.
We do not insure against certain risks and our insurance coverage may not be adequate for covering losses arising from potential operational hazards and unforeseen interruptions.
We insure our operations in accordance with industry practice and plan to continue to insure the risks we consider appropriate for our needs and circumstances. However, we may elect not to have insurance for certain risks, due to the high premium costs associated with insuring those risks or for various other reasons, including an assessment in some cases that the risks are remote.
Our insurance may not be adequate to cover all losses or liabilities we may suffer. We cannot assure that we will be able to obtain insurance coverage at reasonable rates (or at all), or that any coverage we or the relevant operator obtain, and any proceeds of insurance, will be adequate and available to cover any claims arising. We may become subject to liability for pollution, blow-outs or other hazards against which we have not insured or cannot insure, including those in respect of past activities for which we were not responsible. Any indemnities we may receive from sub-contractors, operators or joint venture partners may be difficult to enforce if such sub-contractors, operators or joint venture partners lack adequate resources.
Operational insurance policies are usually placed in one year contracts and the insurance market can withdraw cover for certain risks due to events occurring in other parts of the industry, thus greatly increasing the costs of risk transfer. For example, in September 2018, a gas pipeline operated by another midstream company exploded in Beaver County, Pennsylvania, a state in which we have operations. The explosion resulted in the destruction of residential property and motor vehicles as well as the evacuation of nearby households. Catastrophic events such as these may cause the insurance costs for our midstream operations to rise, despite us not being involved in the catastrophic event. In the event that insurance coverage is not available or our insurance is insufficient to fully cover any losses, including losses incurred due to lost revenues resulting from third party operations or processing plants, claims and/or liabilities incurred, or indemnities are difficult to enforce, our business and operations, financial results or financial position may be disrupted and adversely affected.
The payment by our insurers of any insurance claims may result in increases in the premiums payable by us for our insurance coverage and could adversely affect our financial performance. In the future, some or all of our insurance coverage may become unavailable or prohibitively expensive.
Our internal systems and website may be subject to intentional and unintentional disruption, and our confidential information may be misappropriated, stolen or misused, which could adversely impact our reputation and future sales.
We have faced, and may in the future continue to face, cyber-attacks and data security breaches. Such cyber-attacks and breaches are designed to penetrate our network security or the security of our internal systems, misappropriate proprietary information and/or cause interruptions to our services, and we expect to continue to face similar threats in the future. We cannot guarantee that we will be able to successfully prevent all attacks in the future. Such future attacks could include hackers obtaining access to our systems, the introduction of malicious computer code or denial of service attacks. If an actual or perceived breach of our network security occurs, it could adversely affect our business or reputation, and may expose us to the loss of information, litigation and possible liability. An actual security breach could also impair our ability to operate our business and provide products and services to our customers. Additionally, malicious attacks, including cyber-attacks, may damage our assets, prevent production at our producing assets and otherwise
 
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significantly affect corporate activities. For example, we utilize electronic monitoring of meters and flow rate devices to monitor pressure build-up in our production wells. If there were a cyber-attack that penetrated our monitoring systems such that they provided false readings, this could result in an unknown pressure build-up, creating a dangerous situation which could end up in an explosion. As techniques used to obtain unauthorized access to or to sabotage systems change frequently and may not be known until launched against us or our third-party service providers, we may be unable to anticipate or implement adequate measures to protect against these attacks and our service providers may likewise be unable to do so. Such an outcome would have a material adverse impact on our business, results of operations, financial condition, cash flows or prospects.
In addition, confidential or financial payment information that we maintain may be subject to misappropriation, theft and deliberate or unintentional misuse by current or former employees, third-party contractors or other parties who have had access to such information. Any such misappropriation and/or misuse of our information could result in the Company, among other things, being in breach of certain data protection requirements and related legislation as well as incurring liability to third parties. We expect that we will need to continue closely monitoring the accessibility and use of confidential information in our business, educate our employees and third-party contractors about the risks and consequences of any misuse of confidential information and, to the extent necessary, pursue legal or other remedies to enforce our policies and deter future misuse. If our confidential information is misappropriated, stolen or misused as a result of a disruption to our website or internal systems this could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
Although we maintain insurance to protect against losses resulting from certain of data protection breaches and cyber-attacks, our coverage for protecting against such risks may not be sufficient.
Our operations are subject to the risk of litigation.
From time to time, we may be subject, directly or indirectly, to litigation arising out of our operations and the regulatory environments in our areas of operations. Historically, categories of litigation that we have faced included actions by royalty owners over payment disputes, personal injury claims and property related claims, including claims over property damage, trespass or nuisance. Although we currently face no material litigation that is reasonably expected to have an adverse material impact for which we are not sufficiently indemnified or insured, damages claimed under such litigation in the future may be material or may be indeterminate, and the outcome of such litigation, if determined adversely to us, could individually or in the aggregate, be reasonably expected to have a material and adverse effect on our business, financial position or results of operations. While we assess the merits of each lawsuit and defend ourselves accordingly, we may be required to incur significant expenses or devote significant resources to defend against such litigation. In addition, the adverse publicity surrounding such claims may have a material adverse effect on our business.
We are subject to certain tax risks.
Any change in our tax status or in taxation legislation in the United Kingdom or the United States could affect our ability to provide returns to shareholders. Statements in this document concerning the taxation of holders of our ordinary shares are based on current law and practice, which is subject to change.
We are subject to income taxes in the United Kingdom and the United States, and there can be no certainty that the current taxation regime in the United Kingdom, the United States or other jurisdictions within which we currently operate or may operate in the future will remain in force or that the current levels of corporation taxation will remain unchanged. For example, the U.S. government has imposed a minimum tax on corporations and proposed and may enact significant changes to the taxation of business entities including, among others, an increase in the U.S. federal income tax rate applicable to corporations, like us, and surtaxes on certain types of income. Certain U.S. localities also maintain a severance tax or impact fee on the removal of oil and natural gas from the ground and such tax rates may be increased or new severance taxes or impact fees may be implemented. In addition, in response to current global events and consumer hardship, the United Kingdom announced on May 26, 2022 a new “Energy Profits Levy” on oil and gas exploration and production companies operating in the United Kingdom and the UK Continental Shelf at a rate of 25% (subsequently increased to 35%). As we do not operate our exploration, production or
 
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extraction activities in the United Kingdom or in the UK Continental Shelf, we do not expect the Energy Profits Levy to impact our headline corporation tax rate in the United Kingdom, however, the taxation of energy companies remains uncertain, particularly in the context of current global events, and the future stability of such tax regimes cannot be guaranteed.
Our domestic and international tax liabilities are subject to the allocation of expenses in differing jurisdictions. Our effective tax rate could be adversely affected by changes in the mix of earnings and losses in taxing jurisdictions with differing statutory tax rates, certain non-deductible expenses, the valuation of deferred tax assets and liabilities and changes in federal, state or international tax laws and accounting principles. Increases in our effective tax rate could materially affect our net financial results. Although we believe that our income tax liabilities are reasonably estimated and accounted for in accordance with applicable laws and principles, an adverse resolution of one or more uncertain tax positions in any period could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
In the past we have been able to offset a large portion of our U.S. federal income tax burden with marginal well tax credits that are available to qualified producers who operate lower-volume wells during a low commodity pricing environment. There can be no assurance that there will be no amendment to the existing taxation laws applicable to us, which may have a material adverse effect on our financial position. Our ability to utilize marginal well tax credits in the United States could be or become subject to limitations (for example, if we are deemed to undergo an “ownership change” for applicable U.S. federal income tax purposes).
The nature and amount of tax that we expect to pay and the reliefs expected to be available to us are each dependent upon several assumptions, any one of which may change and which would, if so changed, affect the nature and amount of tax payable and reliefs available. In particular, the nature and amount of tax payable may be dependent on the availability of relief under tax treaties and is subject to changes to the tax laws or practice in any of the jurisdictions we currently are subject to or may be subject to in the future. Any limitation in the availability of relief under these treaties, any change in the terms of any such treaty or any changes in tax law, interpretation or practice could increase the amount of tax payable by us.
Finally, because we are an entity incorporated in the United Kingdom that is treated as a U.S. corporation for all purposes of U.S. federal income tax law, any changes in U.S. federal income tax law could negatively impact our effective tax rate and cash flows, which could cause our business, results of operations, financial condition, cash flows or prospects to be materially adversely affected.
The taxation of an investment in our ordinary shares depends on the individual circumstances of the holders of our ordinary shares. Holders of our ordinary shares are strongly advised to consult their professional tax advisers.
Tax legislation may be enacted in the future that could negatively impact our current or future tax structure and effective tax rates.
Long-standing international tax initiatives that determine each country’s jurisdiction to tax cross-border international trade and profits are evolving as a result of, among other things, initiatives such as the Anti-Tax Avoidance Directives, as well as the Base Erosion and Profit Shifting reporting requirements, mandated and/or recommended by the EU, G8, G20 and Organization for Economic Cooperation and Development, including the imposition of a minimum global effective tax rate for multinational businesses regardless of the jurisdiction of operation and where profits are generated (Pillar Two). As these and other tax laws and related regulations change (including changes in the interpretation, approach and guidance of tax authorities), our financial results could be materially impacted. Given the unpredictability of these possible changes and their potential interdependency, it is difficult to assess whether the overall effect of such potential tax changes would be cumulatively positive or negative for our earnings and cash flow, but such changes could adversely affect our financial results.
Risks Relating to Our Ordinary Shares
Our ordinary shares are subject to market price volatility and the market price may decline disproportionately in response to developments that are unrelated to our operating performance.
The market price of our ordinary shares has been, and may in the future be, volatile and subject to wide fluctuations as a result of a variety of factors including, but not limited to:
 
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operating results that vary from our financial guidance or the expectations of securities analysts and investors;
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the financial performance of the major end markets that we target;
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the operating and securities price performance of companies that investors consider to be comparable to us;
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announcements of strategic developments, acquisitions and other material events by us or our competitors;
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failure to meet or exceed financial estimates and projections of the investment community or that we provide to the public;
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issuance of new or updated research or reports by securities analysts;
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changes in government regulations;
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financing or other corporate transactions;
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the loss of any of our key personnel;
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sales of our ordinary shares by us, our executive officers and board members or our shareholders in the future;
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price and volume fluctuations in the overall stock market, including as a result of trends in the economy as a whole; and
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other events and factors, many of which are beyond our control.
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These and other market and industry factors may cause the market price and demand for our ordinary shares to fluctuate substantially, regardless of our actual operating performance, which may limit or prevent investors from readily selling their ordinary shares and may otherwise negatively affect the liquidity of our ordinary shares. In the past, when the market price of a stock has been volatile, holders of that stock have sometimes instituted securities class action litigation against the issuer. If any of the holders of our ordinary shares were to bring such a lawsuit against us, we could incur substantial costs defending the lawsuit and the attention of our senior management would be diverted from the operation of our business. Any adverse determination in litigation could also subject us to significant liabilities.
Prior to this listing, we had a limited public market in the United States for our ordinary shares, and an active market may not develop in which investors can resell our ordinary shares.
Prior to this listing, there was a limited public market in the United States for our ordinary shares on the OTCQX, although our ordinary shares have traded on the Main Market of the LSE. We cannot predict the extent to which an active market for our ordinary shares in the United States will develop or be sustained or how the development of such a market might affect the market price for our ordinary shares. The initial price of our ordinary shares in the United States will be based on a number of factors, including the trading price of our ordinary shares on the LSE, which may not be indicative of the price at which our ordinary shares will trade following completion of the listing.
The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our ordinary shares. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.
The dual listing of our ordinary shares following this listing may adversely affect the liquidity and value of our ordinary shares.
Following this listing and after our ordinary shares begin trading on the New York Stock Exchange (“NYSE”), our ordinary shares will continue to be admitted to the premium segment of the Official List of
 
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the Financial Conduct Authority and to trading on the Main Market of the LSE. We cannot predict the effect of this dual listing on the value of our ordinary shares. However, the dual listing of our ordinary shares may dilute the liquidity of these securities in one or both markets and may adversely affect the development of an active trading market for our ordinary shares in the United States.
The requirements of being a U.S. public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
Upon becoming a U.S. public company, we will be required to comply with new laws, regulations and requirements, certain corporate governance provisions of Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and will significantly increase our costs and expenses. We will need to: institute a more comprehensive compliance function to test and conclude on the sufficiency of our internal control over financial reporting; comply with rules promulgated by the NYSE; prepare and distribute periodic public reports; establish new internal policies, such as those relating to insider trading; and involve and retain to a greater degree outside professionals in the above activities. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls does not address all relevant financial statement risks. In our second annual report on Form 20-F, our independent registered public accounting firm must attest to the effectiveness of our internal control over financial reporting. Our independent registered public accounting firm may issue a report that concludes it does not believe our internal control over financial reporting is effective. Compliance with Sarbanes-Oxley Act requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a U.S. public company, we will be subject to significant regulatory oversight and reporting obligations under U.S. federal securities laws and the continuous scrutiny of securities analysts and investors. In addition, most members of our management team have limited experience managing a U.S. public company, interacting with U.S. public company investors, and complying with the increasingly complex laws pertaining to U.S. public companies. Our management team may not successfully or efficiently manage us as a U.S. public company. These new obligations and constituents require significant attention from our management team and could divert our management team’s attention away from the day-to-day management of our business, which could adversely affect our business, results of operations and financial condition.
Further, we expect that being a U.S. public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.
We qualify as a foreign private issuer and, as a result, we will not be subject to U.S. proxy rules and will be subject to Exchange Act reporting obligations that, to some extent, are more lenient and less frequent than those of a U.S. domestic public company.
Following this listing, we will report under the Exchange Act as a non-U.S. company with foreign private issuer status. Because we qualify as a foreign private issuer under the Exchange Act, we are exempt from certain provisions of the Exchange Act that are applicable to U.S. domestic public companies, including (i) the sections of the Exchange Act regulating the solicitation of proxies, consents or authorizations in respect of a security registered under the Exchange Act; (ii) the sections of the Exchange Act requiring insiders to file public reports of their stock ownership and trading activities and liability for insiders who profit from trades made in a short period of time; and (iii) the rules under the Exchange Act requiring the filing with the SEC of quarterly reports on Form 10-Q containing unaudited financial and other specified information, or current reports on Form 8-K, upon the occurrence of specified significant events. In addition, foreign private issuers are not required to file their annual report on Form 20-F until 120 days
 
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after the end of each fiscal year, while U.S. domestic issuers that are accelerated filers are required to file their annual report on Form 10-K within 75 days after the end of each fiscal year. Foreign private issuers also are exempt from Regulation Fair Disclosure, aimed at preventing issuers from making selective disclosures of material information. As a result of the above, you may not have the same protections afforded to shareholders of companies that are not foreign private issuers, some investors may find the ordinary shares less attractive, and there may be a less active trading market for the ordinary shares.
As a foreign private issuer, we are permitted to adopt certain home country practices in relation to corporate governance matters that differ significantly from the corporate governance listing standards of the NYSE. These practices may afford less protection to shareholders than they would enjoy if we complied fully with the corporate governance listing standards of the NYSE.
As a foreign private issuer listed on the NYSE, we will be subject to corporate governance listing standards. However, NYSE rules permit a foreign private issuer like us to follow the corporate governance practices of its home country in lieu of certain NYSE corporate governance listing standards, provided that we disclose which requirements that we have not complied with in any year and confirm the UK corporate governance practices we have complied with. Certain corporate governance practices in the United Kingdom, which is our home country, may differ significantly from the NYSE corporate governance listing standards. Although we voluntarily comply with the higher corporate governance standards of the UK Corporate Governance Code, we could include non-independent directors as members of our nomination and remuneration committee, and our independent directors would not necessarily hold regularly scheduled meetings at which only independent directors are present. We may in the future elect to follow home country practices in the United Kingdom with regard to other matters. Therefore, our shareholders may be afforded less protection than they otherwise would have under the NYSE corporate governance listing standards applicable to U.S. domestic issuers. See “Item 6.Directors, Senior Management and Employees — C. Board Practices.”
We may lose our foreign private issuer status, which would then require us to comply with the Exchange Act’s domestic reporting regime and cause us to incur significant legal, accounting and other expenses.
As a foreign private issuer, we are not required to comply with all of the periodic disclosure and current reporting requirements of the Exchange Act applicable to U.S. domestic issuers. To the extent we no longer qualify as a foreign private issuer as of June 30, 2024 (the end of our second fiscal quarter in the fiscal year after this listing), we would be required to comply with all of the periodic disclosure and current reporting requirements of the Exchange Act applicable to U.S. domestic issuers as of July 1, 2024. In order to maintain our current status as a foreign private issuer, either (a) a majority of our ordinary shares must be either directly or indirectly owned of record by non-residents of the United States or (b)(i) a majority of our executive officers or directors cannot be U.S. citizens or residents, (ii) more than 50% of our assets must be located outside the United States and (iii) our business must be administered principally outside the United States. If we lose our status as a foreign private issuer, we would be required to comply with the Exchange Act reporting and other requirements applicable to U.S. domestic issuers, including the requirement to prepare our financial statements in accordance with U.S. generally accepted accounting principles, which are more detailed and extensive than the requirements for foreign private issuers. We may also be required to make changes in our corporate governance practices in accordance with various SEC and NYSE rules. The regulatory and compliance costs to us under U.S. securities laws if we are required to comply with the reporting requirements applicable to a U.S. domestic issuer may be significantly higher than the cost we would incur as a foreign private issuer. As a result, we expect that a loss of foreign private issuer status would increase our legal and financial compliance costs and would make some activities highly time consuming and costly. If we lose foreign private issuer status and are unable to comply with the reporting requirements applicable to a U.S. domestic issuer by the applicable deadlines, we would not be in compliance with applicable SEC rules or the rules of NYSE, which could cause investors could lose confidence in our public reports and could have a material adverse effect on the trading price of our ordinary shares. We also expect that if we were required to comply with the rules and regulations applicable to U.S. domestic issuers, it would make it more difficult and expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These rules and regulations could also make it more difficult for us to attract and retain qualified members of our board of directors.
 
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Failure to comply with requirements to design, implement and maintain effective internal control over financial reporting could have a material adverse effect on our business.
As a UK public company traded on the Main Market of the LSE, we are not required to evaluate our internal control over financial reporting in a manner that meets the rules and regulations of the SEC.
The process of designing and implementing effective internal control over financial reporting is a continuous effort that requires us to anticipate and react to changes in our business and the economic and regulatory environments and to expend significant resources to maintain internal control over financial reporting that is adequate to satisfy our reporting obligations as a U.S. public company. If we are unable to establish or maintain adequate internal control over financial reporting, it could cause us to fail to meet our reporting obligations on a timely basis, result in material misstatements in our consolidated financial statements and harm our results of operations. In addition, we will be required, pursuant to the rules and regulations of the SEC, to furnish a report by management on the effectiveness of our internal control over financial reporting in the second annual report following the completion of this listing. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. Assessing the effectiveness of our internal control over financial reporting will require significant documentation, testing and possible remediation. Testing and maintaining internal control over financial reporting may divert our management’s attention from other matters that are important to our business.
We may not be able to conclude on an annual basis that we have effective internal control over financial reporting or our independent registered public accounting firm may not issue an unqualified opinion on the effectiveness of our internal control over financial reporting. If either we are unable to conclude that we have effective internal control over financial reporting or our independent registered public accounting firm is unable to issue an unqualified opinion on the effectiveness of internal control over financial reporting, investors could lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our ordinary shares.
During the preparation of our December 31, 2021 consolidated financial statements, we identified a material weakness in the design of our internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis.
We did not design and maintain an effective control related to the completeness and accuracy of the data provided to specialists used in business combinations. Although this deficiency did not result in a material misstatement to the consolidated financial statements, this deficiency could result in misstatements in our accounting for acquisitions that we account for as business combinations that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.
During 2022, we implemented a remediation plan, primarily consisting of adding control activities to re-validate the completeness and accuracy of the data provided to specialists throughout the business combination business cycle for each acquisition. While we believe our remediation efforts were successful, we are also not required to evaluate our internal control over financial reporting in a manner that meets the rules and regulations of the SEC given our foreign private issuer status as a UK public company. Our independent registered public accounting firm must attest to and report on the effectiveness of our internal control over financial reporting in our second annual report on Form 20-F. No other material weakness in financial reporting has been identified in the years ended 2021 or 2022, or through June 30, 2023.
We will incur increased costs as a result of operating as a public company in the United States, and our management will be required to devote substantial time to new compliance initiatives and corporate governance practices.
As a U.S. public company, we will incur significant legal, accounting and other expenses that we did not incur previously. The Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the listing requirements of NYSE and other applicable securities rules and regulations impose various
 
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requirements on non-U.S. reporting public companies, including the establishment and maintenance of disclosure controls and procedures, internal control over financial reporting and corporate governance practices. Our management and other personnel will need to devote a substantial amount of time to these compliance initiatives. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time consuming and costly. For example, we expect that these rules and regulations may increase the cost of our director and officer liability insurance.
However, these rules and regulations are often subject to varying interpretations, in many cases due to their lack of specificity, and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices.
Because we may not pay any cash dividends on our ordinary shares in the future, capital appreciation, if any, may be your sole source of gains and you may never receive a return on your investment.
Under current UK law, a company’s accumulated realized profits, so far as not previously utilized by distribution or capitalization, must exceed its accumulated realized losses so far as not previously written off in a reduction or reorganization of capital duly made (on a non-consolidated basis), before dividends can be paid. Therefore, we must have distributable profits before issuing a dividend. Although we historically declared dividends on our ordinary shares, in the future, our board of directors may decide, in its discretion, not to declare and pay dividends based on a number of factors, including our performance and financial condition, cash requirements, future prospects, commodity prices, the performance and dividend yield of our peers, in addition to general economic conditions. Further, the Company’s Credit Facility contains a restricted payment covenant that limits its subsidiaries’ ability to make certain payments with respect to their equity, based on the pro forma effect thereof on certain financial ratios, which would be the source of distributable profits from which we may issue a dividend. Consequently, any historical declared dividends are in no way a guide to potential future dividends and capital appreciation, if any, on our ordinary shares may be your sole source of gains.
There is no guarantee that we will continue to pay dividends on our ordinary shares in the future.
Our ability and the Board’s decision to pay dividends is dependent upon our performance and financial condition, cash requirements, future prospects, commodity prices, the performance and dividend yield of our peers, compliance with the financial covenants and restricted payments covenant in our Credit Facility, profits available for distribution and other factors deemed to be relevant at the time and on the continued health of the markets in which we operate. Further, subsequent to our listing on the NYSE, while our Board’s evaluation of our ability or need to pay dividends will primarily remain a question of the foregoing factors, it will also take into account the performance of our ordinary shares, including relative to our peer group. There can be no guarantee that we will continue to pay dividends in the future on our ordinary shares.
The rights of our shareholders may differ from the rights typically offered to shareholders of a U.S. corporation.
We are incorporated under UK law. The rights of holders of ordinary shares are governed by UK law, including the provisions of the UK Companies Act 2006 (the “Companies Act 2006”), and by our Articles of Association. These rights differ in certain respects from the rights of shareholders in typical U.S. corporations. See “Item 10. Additional Information — B. Memorandum and Articles of Association” in this registration statement for a description of the principal differences between the provisions of the Companies Act 2006 applicable to us and, for example, the Delaware General Corporation Law relating to shareholders’ rights and protections.
Claims of U.S. civil liabilities may not be enforceable against us.
We are incorporated under the laws of the United Kingdom. In addition, certain of our directors and officers reside outside the United States. As a result, it may not be possible for investors to effect service of process within the United States upon such persons or to enforce judgments obtained in U.S. courts against them or us, including judgments predicated upon the civil liability provisions of the U.S. federal securities laws.
 
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The United States and the United Kingdom do not currently have a treaty providing for recognition and enforcement of judgments (other than arbitration awards) in civil and commercial matters. Consequently, a final judgment for payment given by a court in the United States, whether or not predicated solely upon U.S. securities laws, would not automatically be recognized or enforceable in the United Kingdom. In addition, uncertainty exists as to whether UK courts would entertain original actions brought in the UK against us or our directors or senior management predicated upon the securities laws of the United States or any state in the United States. Provided that certain requirements are met, a final and conclusive monetary judgment for a definite sum obtained against us in U.S. courts (that is not a sum payable in respect of taxes or similar charges or in respect of a fine or a penalty), would be treated by the courts of the UK as a cause of action in itself and sued upon as a debt at common law without any retrial of the issue. Whether the relevant requirements are met in respect of a judgment based upon the civil liability provisions of the U.S. securities laws, including whether the award of monetary damages under such laws would constitute a penalty, is an issue for the court making such decision. If a UK court gives judgment for the sum payable under a U.S. judgment, the UK judgment will be enforceable by methods generally available for this purpose. These methods generally permit the UK court discretion to prescribe the manner of enforcement.
As a result, U.S. investors may not be able to enforce against us or our executive officers, board of directors or certain experts named herein who are residents of the United Kingdom or countries other than the United States any judgments obtained in U.S. courts in civil and commercial matters, including judgments under the U.S. federal securities laws.
General Risks
Events of force majeure may limit our ability to operate our business and could adversely affect our operating results.
The weather, unforeseen events, or other events of force majeure in the areas in which we operate could cause disruptions or suspension of our operations. This suspension could result from a direct impact to our properties or result from an indirect impact by a disruption or suspension of the operations of those upon whom we rely for gathering and transportation. If disruption or suspension were to persist for a long period, our results of operations would be materially impacted.
If securities or industry analysts do not publish research, or publish inaccurate or unfavorable research, about our business, the price of our ordinary shares and our trading volume could decline.
The trading market for our ordinary shares will depend in part on the research and reports that securities or industry analysts publish about us or our business. Securities and industry analysts do not currently, and may never, publish research on us. If no or too few securities or industry analysts commence coverage on us, the trading price for our ordinary shares would likely be negatively affected. In the event securities or industry analysts initiate coverage, if one or more of the analysts who cover us downgrade our ordinary shares or publish inaccurate or unfavorable research about our business, the price of our ordinary shares would likely decline. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, demand for our ordinary shares could decrease, which might cause the price of our ordinary shares and trading volume to decline.
Item 4.   Information on the Company.
A.   History and Development of the Company
The Company, formerly Diversified Gas & Oil plc, is an independent energy company engaged in the production, marketing and transportation of natural gas as well as oil from its complementary onshore upstream and midstream assets, primarily located within the Appalachian and Central Regions of the United States. Our Appalachia assets consist primarily of producing wells in conventional reservoirs and the Marcellus and Utica shales, within Pennsylvania, Ohio, Virginia, West Virginia, Kentucky, and Tennessee, while our Central Region, located in Oklahoma, Louisiana, and portions of Texas, includes producing wells in multiple producing formations, including the Bossier, Haynesville Shale and Barnett Shale Plays, as well as the Cotton Valley and the Mid-Continent producing areas. We were incorporated in 2014 in the United
 
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Kingdom, and our predecessor business was founded in 2001 by our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., with an initial focus on primarily natural gas and also oil production in West Virginia. In recent years, we have grown rapidly by capitalizing on opportunities to acquire and enhance producing assets and leveraging the operating efficiencies that result from economies of scale. Since 2017, and through June 30, 2023, we have completed 24 acquisitions for a combined purchase price of approximately $2.6 billion. We had average daily production of 852 MMcfepd and 811 MMcfepd for the six months ended June 30, 2023 and for the year ended December 31, 2022, respectively.
We have consistently driven our operations towards sustainability and efficiency throughout our history, but we believe we are also at the forefront of U.S. natural gas and oil producers in our commitment to ESG goals. While the global energy economy is reliant on natural gas as an energy source, we believe it is imperative that natural gas wells and pipelines be operated by responsible owners with a strong commitment to the environment, and we believe our operational track record demonstrates that responsibility and stewardship. Given our operational focus on efficient, environmentally sound natural gas production, we believe we are ideally positioned to help serve current energy demands and play a key role in the clean energy transition.
Recent Developments
We announced on July 17, 2023 the sale of undeveloped acres in Oklahoma, within the Company’s Central Region, for net consideration of approximately $16 million.
We announced on September 26, 2023 that we completed the semi-annual borrowing base redetermination of our revolving Credit Facility. The borrowing base under the Credit Facility was increased to $425 million reflective of the addition of certain collateral previously acquired from EQT and certain smaller operators in Appalachia.
Other Information
We were incorporated as a public limited company with the legal name Diversified Gas & Oil plc under the laws of the United Kingdom on July 31, 2014 with the company number 09156132. On May 6, 2021, we changed our company name to Diversified Energy Company plc.
Our registered office is located at 4th Floor Phoenix House, 1 Station Hill, Reading, Berkshire United Kingdom, RG1 1NB. In February 2017, our shares were admitted to trading on the AIM Market of the London Stock Exchange (“AIM”) under the ticker “DGOC.” In May 2020, our shares were admitted to the premium segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE. The shares trading on AIM were cancelled concurrent to their admittance on the LSE. With the change in corporate name in 2021, our shares listed on the LSE began trading under the new ticker “DEC.”
Our principal executive offices are located at 1600 Corporate Drive, Birmingham, Alabama 35242, and our telephone number at that location is +1 205 408 0909. Our website address is www.div.energy. The information contained on, or that can be accessed from, our website does not form part of this registration statement. We have included our website address solely as an inactive textual reference.
For a description of our principal capital expenditures and divestitures for the three years ended December 31, 2022 and for those currently in progress, see “Item 5. Operating and Financial Review and Prospects”.
B.   Business Overview
Our strategy is primarily to acquire and manage natural gas and oil properties while leveraging our associated midstream assets to maximize cash flows. We seek to improve the performance and operations of our acquired assets through our deployment of rigorous field management programs and/or refreshing infrastructure. Through operational efficiencies, we demonstrate our ability to maximize value by enhancing production while lowering costs and improving well productivity. We adhere to stringent operating standards, with a strong focus on health, safety and the environment to ensure the safety of our employees and the local communities in which we operate. We believe that acting as a careful steward of our assets will
 
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improve revenue and margins through captured natural gas emissions while reducing operating costs, which benefits our profitability. This focus on operational excellence, including the aim of reducing natural gas emissions, also benefits the environment and communities in which we operate.
Our Business Strategy
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Optimization of long-life, low-decline assets to enhance margins and improve cash flow
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Generate consistent shareholder returns through vertical integration, strategic hedging and cost optimization
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Disciplined growth through accretive acquisitions of producing assets
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Maintain a strong balance sheet with ability to opportunistically access capital markets
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Operate assets in a safe, efficient manner with what we believe are industry-leading ESG initiatives
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Our Strengths
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Low-risk and low-cost portfolio of assets
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Long-life and low-decline production
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High margin assets benefiting from significant scale and owned midstream and asset retirement infrastructure
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Highly experienced management and operational team
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Track record of successful consolidation and integration of acquired assets
​
Outlook
Looking forward, we will continue to prudently manage our long-life, low-decline asset portfolio and the consistent cashflows they produce. We plan to maintain our hedging strategy to protect cash flow. We will seek to retain our strategic advantages in purposeful growth through a disciplined acquisition strategy that continues to secure low-cost financing that supports acquisitive growth while maintaining low leverage and ample liquidity. In addition, we intend to remain proactive in our ESG endeavors by seeking to secure future capital allocation for ESG initiatives.
Reserve Data
Summary of Reserves
The following table presents our estimated net proved reserves, Standardized Measure and PV-10 as of December 31, 2022, using SEC pricing. Standardized Measure has been presented inclusive and exclusive of taxes and is based on the proved reserve report as of such date by NSAI, our independent petroleum engineering firm. A copy of the proved reserve report is included as an exhibit to the registration statement of which this registration statement forms a part. See the below subsections titled “— Preparation of Reserve Estimates” and “— Estimation of Proved Reserves” for a definition of proved reserves and the technologies and economic data used in their estimation.
 
39
 
​ ​ ​
December 31, 2022
​
​ ​ ​
SEC Pricing(1)
​
Proved developed reserves ​ ​ ​ ​ ​ ​ ​
Natural gas (MMcf)
​ ​ ​ ​ 4,340,779 ​ ​
NGLs (MBbls)
​ ​ ​ ​ 101,931 ​ ​
Oil (MBbls)
​ ​ ​ ​ 14,830 ​ ​
Total proved developed reserves (MBoe)
​ ​ ​ ​ 840,224 ​ ​
Proved undeveloped reserves ​ ​ ​ ​ ​ ​ ​
Natural gas (MMcf)
​ ​ ​ ​ 8,832 ​ ​
NGLs (MBbls)
​ ​ ​ ​ — ​ ​
Oil (MBbls)
​ ​ ​ ​ — ​ ​
Total proved undeveloped reserves (MBoe)
​ ​ ​ ​ 1,472 ​ ​
Total proved reserves ​ ​ ​ ​ ​ ​ ​
Natural gas (MMcf)
​ ​ ​ ​ 4,349,611 ​ ​
NGLs (MBbls)
​ ​ ​ ​ 101,931 ​ ​
Oil (MBbls)
​ ​ ​ ​ 14,830 ​ ​
Total proved reserves (MBoe)
​ ​ ​ ​ 841,696 ​ ​
Prices used ​ ​ ​ ​ ​ ​ ​
Natural gas (MMBtu)
​ ​ ​ $ 6.36 ​ ​
Oil and NGLs (Bbls)
​ ​ ​ $ 94.14 ​ ​
PV-10 (thousands) ​ ​ ​ ​ ​ ​ ​
Pre-tax (Non-GAAP)(2)
​ ​ ​ $ 8,825,462 ​ ​
PV of Taxes
​ ​ ​ ​ (2,082,362) ​ ​
Standardized Measure
​ ​ ​ $ 6,743,100 ​ ​
Percent of estimated total proved reserves that are: ​ ​ ​ ​ ​ ​ ​
Natural gas
​ ​ ​ ​ 86.1% ​ ​
Proved developed
​ ​ ​ ​ 99.8% ​ ​
Proved undeveloped
​ ​ ​ ​ 0.2% ​ ​
​
(1)
Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For natural gas volumes, the average Henry Hub spot price of $6.36 per MMBtu as of December 31, 2022 was adjusted for gravity, quality, local conditions, gathering and transportation fees, and distance from market. For NGLs and oil volumes, the average WTI price of $94.14 per Bbl as of December 31, 2022 was similarly adjusted for gravity, quality, local conditions, gathering and transportation fees, and distance from market. All prices are held constant throughout the lives of the properties.
​
(2)
The PV-10 of our proved reserves as of December 31, 2022 was prepared without giving effect to taxes or hedges. PV-10 is a non-GAAP and non-IFRS financial measure and generally differs from Standardized Measure, the most directly comparable GAAP measure, because it does not include the effects of income taxes on future net cash flows. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the Standardized Measure because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. While the Standardized Measure is free cash dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. Investors should be cautioned that neither PV-10 nor the Standardized Measure represents an estimate of the fair market value of our proved reserves.
​
 
40
 
Proved Reserves
As of December 31, 2022, our estimated proved reserves totaled 842 MMBoe, an increase of 9.1% from the prior year-end with a Standardized Measure of $6.7 billion. Natural gas constituted approximately 86.1% of our total estimated proved reserves and 86.1% of our total estimated proved developed reserves. The following table provides a summary of the changes in our proved reserves for the years ended December 31, 2022, 2021 and 2020.
​ ​ ​
Total (MBoe)
​
Total proved reserves as of December 31, 2019
​ ​ ​ ​ 535,979 ​ ​
Extensions and discoveries
​ ​ ​ ​ — ​ ​
Revisions to previous estimates
​ ​ ​ ​ (65,911) ​ ​
Purchase of reserves in place
​ ​ ​ ​ 108,781 ​ ​
Sales of reserves in place
​ ​ ​ ​ (547) ​ ​
Production
​ ​ ​ ​ (36,538) ​ ​
Total proved reserves as of December 31, 2020
​ ​ ​ ​ 541,765 ​ ​
Extensions and discoveries
​ ​ ​ ​ — ​ ​
Revisions to previous estimates
​ ​ ​ ​ 90,251 ​ ​
Purchase of reserves in place
​ ​ ​ ​ 210,086 ​ ​
Sales of reserves in place
​ ​ ​ ​ (27,340) ​ ​
Production
​ ​ ​ ​ (43,257) ​ ​
Total proved reserves as of December 31, 2021
​ ​ ​ ​ 771,505 ​ ​
Extensions and discoveries
​ ​ ​ ​ 2,221 ​ ​
Revisions to previous estimates
​ ​ ​ ​ 63,302 ​ ​
Purchase of reserves in place
​ ​ ​ ​ 55,174 ​ ​
Sales of reserves in place
​ ​ ​ ​ (1,152) ​ ​
Production
​ ​ ​ ​ (49,354) ​ ​
Total proved reserves as of December 31, 2022
​ ​ ​ ​ 841,696 ​ ​
Extensions and Discoveries
In 2022, we elected to participate in select development activities on a non-operated basis generating 2,221 MBoe in reserves.
During 2021, no reserves were added from extension or discovery activities.
During 2020, no reserves were added from extension or discovery activities.
Revisions to Previous Estimates
During 2022, we recorded 63,302 MBoe in revisions to previous estimates. These positive performance revisions were primarily associated with changes in the trailing 12-month average realized Henry Hub spot price, which increased approximately 77% as compared to the December 31, 2021 Henry Hub spot price due to the war between Russia and Ukraine, as well as other geopolitical factors. These factors primarily drove a net upward revision of 64,344 MBoe due to changes in pricing that impacted well economics. These increases were offset by a 1,042 MBoe downward revision for changes in timing.
During 2021, 90,251 MBoe in revisions to previous estimates were primarily associated with changes in the 12-month average realized Henry Hub spot price, which increased approximately 81% as compared to December 31, 2020.
During 2020, 65,911 MBoe in revisions to previous estimates were primarily associated with changes in the 12-month average realized Henry Hub spot price, which decreased approximately 24% as compared to December 31, 2019.
 
41
 
Purchase of Reserves in Place
During 2022, 55,174 MBoe of purchases of reserves in place were associated with the East Texas and ConocoPhillips acquisitions. Refer to Note 5 in the Notes to the Consolidated Financial Statements found elsewhere in this registration statement for additional information about these acquisitions.
During 2021, 210,086 MBoe of purchases of reserves in place were associated with the Indigo, Tanos, Blackbeard and Tapstone acquisitions. Refer to Note 5 in the Notes to the Consolidated Financial Statements found elsewhere in this registration statement for additional information about these acquisitions.
During 2020, 108,781 MBoe of purchases of reserves in place were associated with the Carbon and EQT acquisitions. Refer to Note 5 in the Notes to the Consolidated Financial Statements found elsewhere in this registration statement for additional information about these acquisitions.
Sales of Reserves in Place
During 2022, 1,152 MBoe of sales of reserves in place were primarily associated with the divestitures of non-core assets.
During 2021, 27,340 MBoe of sales of reserves in place were primarily associated with the divestment of assets to Oaktree for their subsequent participation in the Indigo acquisition. Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information about divestitures.
During 2020, 547 MBoe of sales of reserves in place were primarily associated with the divestitures of non-core assets.
Productive Wells
Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interest owned in gross wells. The following table summarizes our productive natural gas and oil wells as of December 31, 2022.
​ ​ ​
As of
December 31,
2022
​
Total gross productive wells
​ ​ ​ ​ 77,598 ​ ​
Natural gas wells
​ ​ ​ ​ 74,690 ​ ​
Oil wells
​ ​ ​ ​ 2,908 ​ ​
Total net productive wells
​ ​ ​ ​ 62,176 ​ ​
Natural gas wells
​ ​ ​ ​ 60,847 ​ ​
Oil wells
​ ​ ​ ​ 1,329 ​ ​
​ ​ ​
As of
December 31,
2022(1)
​
Total gross in progress wells
​ ​ ​
​
7
 ​ ​
Total net in progress wells
​ ​ ​
​
1
 ​ ​
​
(1)
Comprised of wells in the Appalachian Region.
​
 
42
 
Exploratory and Development Drilling Activities
Information regarding our drilling and development activities is set forth below:
​ ​ ​
Development
​
​ ​ ​
Productive Wells
​ ​
Dry Wells
​ ​
Total
​
Year
​ ​
Gross
​ ​
Net
​ ​
Gross
​ ​
Net
​ ​
Gross
​ ​
Net
​
2022
​ ​ ​ ​ 5 ​ ​ ​ ​ ​ 2 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 5 ​ ​ ​ ​ ​ 2 ​ ​
2021
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
2020
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
We drilled no exploratory wells (productive or dry) during the years ended December 31, 2022, 2021 and 2020.
During 2021, we completed the Tapstone Acquisition, which included five wells in the Central Region that were under development by Tapstone as of December 31, 2021. We engaged third parties to complete this development activity, however they remained in progress as of December 31, 2021.
During 2022, we completed the development of the five wells referenced in the preceding paragraph that had been under development as of December 31, 2021. We then elected to participate in seven development opportunities on a non-operating basis in our Appalachian Region. All seven of the Appalachian development wells remained in progress as of December 31, 2022. As of the date of this registration statement, two of the Appalachian development wells have been completed and five remain in progress.
Proved Undeveloped Reserves
We aim to obtain proved developed producing wells through acquisitions in accordance with our growth strategy rather than through development activities. We accordingly contribute limited capital to development activities. From time to time, when acquiring packages of wells, we will acquire certain locations that are in development by the acquiree at the time of the acquisition or could be developed in the future. When economic, we will engage third parties to complete the existing development activities, and such reserves are included below as proved undeveloped reserves. We do not have a development program and, as a result, any additional undrilled locations that we hold cannot be classified as undeveloped reserves in accordance with SEC rules unless a development plan is in place. As of December 31, 2022, we had no such development plans and therefore have not classified these undrilled locations as proved undeveloped reserves.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2020, 2021 and 2022:
​ ​ ​
Total
(MBoe)
​
Proved undeveloped reserves as of December 31, 2019
​ ​ ​ ​ — ​ ​
Extensions and discoveries
​ ​ ​ ​ — ​ ​
Revisions to previous estimates
​ ​ ​ ​ — ​ ​
Purchase of reserves in place
​ ​ ​ ​ — ​ ​
Sales of reserves in place
​ ​ ​ ​ — ​ ​
Converted to proved developed reserves
​ ​ ​ ​ — ​ ​
Proved undeveloped reserves as of December 31, 2020
​ ​ ​ ​ — ​ ​
Extensions and discoveries
​ ​ ​
​
—
 ​ ​
Revisions to previous estimates
​ ​ ​
​
—
 ​ ​
Purchase of reserves in place
​ ​ ​
​
584
 ​ ​
Sales of reserves in place
​ ​ ​
​
—
 ​ ​
Converted to proved developed reserves
​ ​ ​
​
—
 ​ ​
 
43
 
​ ​ ​
Total
(MBoe)
​
Proved undeveloped reserves as of December 31, 2021
​ ​ ​ ​ 584 ​ ​
Extensions and discoveries
​ ​ ​ ​ 1,472 ​ ​
Revisions to previous estimates
​ ​ ​ ​ — ​ ​
Purchase of reserves in place
​ ​ ​ ​ — ​ ​
Sales of reserves in place
​ ​ ​ ​ — ​ ​
Converted to proved developed reserves
​ ​ ​ ​ (584) ​ ​
Proved undeveloped reserves as of December 31, 2022
​ ​ ​ ​ 1,472 ​ ​
​
Extensions and Discoveries
During 2022, we elected to participate in select development activities where third parties were engaged to complete the development. Seven of these wells were in progress as of December 31, 2022, generating 1,472 MBoe in proved undeveloped reserves.
During 2021, no reserves were added from extension or discovery activities.
During 2020, no reserves were added from extension or discovery activities.
Purchase of Reserves in Place
There were no purchases of proved undeveloped reserves in place during 2022.
During 2021, the 584 MBoe of purchase of reserves in place were associated with the Tapstone Acquisition and related to five wells that were under development as of December 31, 2021. We engaged third parties to complete this development activity and during 2022 these were converted to proved developed reserves. Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information about acquisitions.
During 2020, there were no purchases of proved undeveloped reserves in place.
Converted to Proved Developed Reserves
During 2022, we completed the development of the five wells referenced in the preceding paragraph that were under development as of December 31, 2021, thereby converting those wells to proved developed reserves. Total capital expenditures in connection with converting those wells to proved developed reserves were approximately $20 million.
During 2021, no reserves were converted to proved developed reserves.
During 2020, no reserves were converted to proved developed reserves.
Developed and Undeveloped Acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2022. Developed acres are acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. Approximately 92% of our acreage was held by production at December 31, 2022.
​ ​ ​
Developed Acreage
​ ​
Undeveloped Acreage
​ ​
Total Acreage
​
​ ​ ​
Gross(1)
​ ​
Net(2)
​ ​
Gross(1)
​ ​
Net(2)
​ ​
Gross(1)
​ ​
Net(2)
​
As of December 31, 2022
​ ​ ​ ​ 5,049,469 ​ ​ ​ ​ ​ 2,742,117 ​ ​ ​ ​ ​ 8,009,257 ​ ​ ​ ​ ​ 5,516,466 ​ ​ ​ ​ ​ 13,058,726 ​ ​ ​ ​ ​ 8,258,583 ​ ​
​
(1)
A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
​
 
44
 
(2)
A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
​
The undeveloped acreage numbers presented in the table above have been compiled using best efforts to review and determine acreage that is not currently drilled but may be available for drilling at the current time under certain circumstances. Whether or not undrilled acreage may be drilled and thereafter produce economic quantities of oil or gas is related to many factors which may change over time, including oil and gas prices, service vendor availability, regulatory regimes, midstream markets, end user demand, and macro and micro financial conditions; the undeveloped acreage described herein is presented without an opinion as to economic viability, as a result of the aforesaid factors. Additionally, it is noted that certain formations on a land tract may be already developed while other formations are undeveloped.
The following table sets forth the number of total gross and net undeveloped acres as of December 31, 2022 that will expire in 2023, 2024 and 2025 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such acreage is extended or renewed.
​ ​ ​
Gross
​ ​
Net
​
2023
​ ​ ​ ​ 680,886 ​ ​ ​ ​ ​ 678,191 ​ ​
2024
​ ​ ​ ​ 3 ​ ​ ​ ​ ​ 3 ​ ​
2025
​ ​ ​ ​ 344 ​ ​ ​ ​ ​ 29 ​ ​
Our primary focus is to operate our existing producing assets in a safe, efficient and responsible manner, however we also assess areas subject to lease expiration for potential development opportunities when prudent. As of December 31, 2022, we had no development plans other than the in-progress wells described above and therefore have not classified any other potential undrilled locations on this acreage as proved undeveloped reserves.
Preparation of Reserve Estimates
Our reserve estimates as of December 31, 2022 included in this registration statement were independently evaluated by our independent engineers, NSAI, in accordance with petroleum engineering and evaluation standards published by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC.
NSAI is a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg and Mr. William J. Knights. Mr. Barg, a Licensed Professional Engineer in the State of Texas (No. 71658), has been practicing consulting petroleum engineering at NSAI since 1989 and has over six years of prior industry experience. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Knights, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1532), has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology in 1984 with a Master of Science Degree in Geology. Both technical principals meet or exceed the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations, as well as applying SEC and other industry reserves definitions and guidelines.
Our internal staff of petroleum engineers and geoscience professionals work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve evaluation process. Our technical team regularly meets with the independent reserve engineers to review properties and discuss methods and assumptions used to prepare reserve estimates. The reserve estimates and related reports are reviewed and approved by our Vice President
 
45
 
of Reservoir Engineering. The Vice President of Reservoir Engineering has been with the Company since 2018 and has 24 years of experience in petroleum engineering, with over 20 years of experience evaluating natural gas and oil reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining the Company in 2018, our Vice President of Reservoir Engineering served in various reservoir engineering roles for public companies engaged in the exploration and production operations, and is also a member of the Society of Petroleum Engineers.
Estimation of Proved Reserves
Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, micro-seismic data and well-test data.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of natural gas, NGLs and oil that are ultimately recovered. Estimates of economically recoverable natural gas, NGLs and oil and of future net cash flows are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Item 3. Key Information — D. Risk Factors” for additional information.
Production Volumes, Average Sales Prices and Operating Costs
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Production ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural Gas (MMcf)
​ ​ ​ ​ 255,597 ​ ​ ​ ​ ​ 234,643 ​ ​ ​ ​ ​ 199,667 ​ ​
NGLs (MBbls)
​ ​ ​ ​ 5,200 ​ ​ ​ ​ ​ 3,558 ​ ​ ​ ​ ​ 2,843 ​ ​
Oil (MBbls)
​ ​ ​ ​ 1,554 ​ ​ ​ ​ ​ 592 ​ ​ ​ ​ ​ 417 ​ ​
Total production (MBoe)
​ ​ ​ ​ 49,354 ​ ​ ​ ​ ​ 43,257 ​ ​ ​ ​ ​ 36,538 ​ ​
Average realized sales price ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(excluding impact of derivatives settled in cash) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas (Mcf)
​ ​ ​ $ 6.04 ​ ​ ​ ​ $ 3.49 ​ ​ ​ ​ $ 1.72 ​ ​
NGLs (Bbls)
​ ​ ​ ​ 36.29 ​ ​ ​ ​ ​ 32.53 ​ ​ ​ ​ ​ 8.15 ​ ​
Oil (Bbls)
​ ​ ​ ​ 89.85 ​ ​ ​ ​ ​ 65.26 ​ ​ ​ ​ ​ 36.12 ​ ​
Total (Boe)
​ ​ ​ $ 37.95 ​ ​ ​ ​ $ 22.50 ​ ​ ​ ​ $ 10.45 ​ ​
Average realized sales price ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(including impact of derivatives settled in cash) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas (Mcf)
​ ​ ​ $ 2.98 ​ ​ ​ ​ $ 2.36 ​ ​ ​ ​ $ 2.33 ​ ​
NGLs (Bbls)
​ ​ ​ ​ 19.84 ​ ​ ​ ​ ​ 15.52 ​ ​ ​ ​ ​ 13.95 ​ ​
Oil (Bbls)
​ ​ ​ ​ 72.00 ​ ​ ​ ​ ​ 71.68 ​ ​ ​ ​ ​ 52.97 ​ ​
Total (Boe)
​ ​ ​ $ 19.80 ​ ​ ​ ​ $ 15.08 ​ ​ ​ ​ $ 14.40 ​ ​
 
46
 
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Operating costs per Boe ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
LOE(1)
​ ​ ​ $ 3.70 ​ ​ ​ ​ $ 2.76 ​ ​ ​ ​ $ 2.53 ​ ​
Production taxes(2)
​ ​ ​ ​ 1.50 ​ ​ ​ ​ ​ 0.71 ​ ​ ​ ​ ​ 0.38 ​ ​
Midstream operating expense(3)
​ ​ ​ ​ 1.44 ​ ​ ​ ​ ​ 1.40 ​ ​ ​ ​ ​ 1.45 ​ ​
Transportation expense(4)
​ ​ ​ ​ 2.39 ​ ​ ​ ​ ​ 1.86 ​ ​ ​ ​ ​ 1.24 ​ ​
Total operating expense per Boe
​ ​ ​ $ 9.03 ​ ​ ​ ​ $ 6.73 ​ ​ ​ ​ $ 5.58 ​ ​
​
​
(1)
LOE is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.
​
(2)
Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural gas, NGLs and oil production at fixed rates established by federal, state or local taxing authorities. Property taxes are generally based on the taxing jurisdictions’ valuation of our natural gas and oil properties and midstream assets.
​
(3)
Midstream operating expenses are daily costs incurred to operate our owned midstream assets inclusive of employee and benefit expenses.
​
(4)
Transportation expenses are daily costs incurred from third-party systems to gather, process and transport our natural gas, NGLs and oil.
​
Significant Fields
The Company operates in four primary fields: (i) Appalachia, which is comprised of the stacked Marcellus and Utica shales (ii) East Texas and Louisiana, which consists of the stacked Cotton Valley, Haynesville, and Bossier shales, (iii) the Barnett Shale and (iv) the Midcontinent region, in North Texas and Oklahoma, which also consists of various stacked plays. The following table presents production for the Company’s Appalachian region, which is considered significant, or greater than 15% of the Company’s total proved reserves.
​ ​ ​
Appalachia
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Production ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural Gas (MMcf)
​ ​ ​ ​ 180,194 ​ ​ ​ ​ ​ 201,635 ​ ​ ​ ​ ​ 199,667 ​ ​
NGLs (MBbls)
​ ​ ​ ​ 2,810 ​ ​ ​ ​ ​ 2,690 ​ ​ ​ ​ ​ 2,843 ​ ​
Oil (MBbls)
​ ​ ​ ​ 423 ​ ​ ​ ​ ​ 446 ​ ​ ​ ​ ​ 417 ​ ​
Total production (MBoe)
​ ​ ​ ​ 33,265 ​ ​ ​ ​ ​ 36,743 ​ ​ ​ ​ ​ 36,538 ​ ​
Customers
Our production is generally sold on month-to-month contracts at prevailing market prices. During the year ended December 31, 2022, no customers individually comprised more than 10% of total revenues. During the year ended December 31, 2021, two customers individually comprised more than 10% of total revenues, representing 22% of consolidated revenues. During the year ended December 31, 2020, two customers individually comprised more than 10% of total revenues, representing 22% of consolidated revenues.
Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security.
 
47
 
Delivery Commitments
We have contractually agreed to deliver firm quantities of natural gas to various customers, which we expect to fulfill with production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet these commitments. The following table summarizes our total gross commitments, compiled using best estimates based on our sales strategy, as of December 31, 2022.
​ ​ ​
Natural gas
(MMcf)
​
2023
​ ​ ​ ​ 61,367 ​ ​
2024
​ ​ ​ ​ 44,162 ​ ​
2025
​ ​ ​ ​ 972 ​ ​
Thereafter
​ ​ ​ ​ — ​ ​
Transportation and Marketing
Diversified Energy Marketing, LLC, our wholly owned marketing subsidiary, provides marketing services and contractual pipeline capacity management services primarily for our benefit, but also to certain third parties.
Our transportation infrastructure is diversified and allows us to capitalize on strengthening markets while also providing reliable takeaway capacity. This is principally achieved through our vertically integrated midstream systems and the synergistic nature of our asset base. As a result, our midstream infrastructure allows for access to advantageous pricing year-round and flow assurance while entering into minimal firm transportation agreements.
When prudent, however, we enter into arrangements that capture opportunities related to the marketing and transportation of natural gas, NGLs and oil, which primarily involve the marketing of our own equity production and that of royalty owners that hold interests in our wells. Additionally, from time-to-time, we assume firm transportation agreements when acquiring wells.
Our midstream systems, as well as our arrangements, allow us to access growing high-demand markets in the U.S. Gulf Coast region while low-cost transportation on northeast pipelines allows us to capture in-basin pricing. Certain of our capacity agreements contain multiple extension and reduction options that allow us to adjust our transportation infrastructure as necessary for our production or to capture future market opportunities. As of December 31, 2022, our transportation arrangements provide access to 636 MMcfepd of takeaway capacity. These firm transportation agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.
To date, we have not experienced significant difficulty in transporting or marketing our natural gas, NGLs and oil production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production. See “Risk Factors — Risks Relating to Our Business, Operations and Industry — We may experience delays in production, marketing and transportation.”
Competition
Our marketing activities compete with numerous other companies offering the same services, many of which possess larger financial and other resources than we have. Some of these competitors are other producers and affiliates of companies with extensive pipeline systems that are used for transportation from producers to end users. Other factors affecting competition are the cost and availability of alternative fuels, the level of consumer demand and the cost of and proximity to pipelines and other transportation facilities. We believe that our ability to compete effectively within the marketing segment in the future depends upon establishing and maintaining strong relationships with customers.
Seasonality
Demand for natural gas and oil generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies and consumers procurement initiatives
 
48
 
can also lessen seasonal demand fluctuations. Seasonal anomalies can increase competition for equipment, supplies and personnel and can lead to shortages and increase costs or delay our operations.
Title to Properties
We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring producing wells, we endeavor to perform a title investigation on an appropriate portion of the properties that is thorough and is consistent with standard practice in the natural gas and oil industry. Generally, we conduct a title examination and perform curative work with respect to significant defects that we identify on properties that we operate. We believe that we have performed reasonable and protective title reviews with respect to an appropriate cross-section of our operated natural gas and oil wells.
Environmental, Health and Safety
Overview
Environmental, health, and safety (“EHS”) management remains a top priority for our company, and we demonstrate our commitment to environmental stewardship in the communities in which we live and operate.
We believe that good business includes improving the safety of assets we have acquired, eliminating and reducing fugitive emissions, consolidating duplicative pipeline networks, eliminating excessive compression facilities and extending the lives of producing wells in order to offset the need to generate supply from newly drilled wells. We seek to take a rigorous approach to managing the potential impacts of production fluid spills, which may include natural gas liquids, oil or produced water. Proper waste management and protection of biodiversity are of high importance to us, and we continuously work to mitigate or manage any impact from these spills.
Our board of directors and employees have a shared commitment to becoming good and trusted stewards of the environment, to ensure that our operations meet or exceed all applicable EHS standards, and to achieve EHS excellence.
We expect a similar commitment to safety and environmental stewardship from our business partners with whom we conduct business, so we utilize a leading supply chain risk management firm to help us prescreen contractors with high safety performance records and then to continuously monitor the contractors’ performance for ongoing compliance with our own expectations as well as with state and federal operating standards.
Total Recordable Incident Rate
We strive to maintain a zero-harm working environment and remain steadfast in our commitment to improving safety performance throughout our footprint. The goal of our occupational health and safety program is to foster a safe and healthy occupational environment for employees and other stakeholders that encounter our operations. Health and safety is a top priority for us and is underscored by our operating performance, as well as our daily operational goals of promoting “Safety — No Compromises.” Our Total Recordable Incident Rate (“TRIR”), defined as the sum of lost time injuries, restricted work injuries and medical treatment injuries per 200,000 work hours, and represents all injuries that require medical treatment in excess of simple first aid, exceeded our goals in 2022 and in 2021 and was driven by a lower frequency of minor incidents throughout the year. Our much improved result in 2022 included several months where we incurred no safety incidents across the organization, reflective of the consistent and continual focus we are investing in our employees. As with any kind of company incident, our senior operations and EHS leadership teams review results with a specific emphasis on root causes and change improvements to
 
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mitigate future incidents. These mitigation efforts are shared with all employees, whether new to the Company following an acquisition or a long-term employee, to help ensure improved performance in the future.
Preventable Motor Vehicle Accident Rate
With more than 1,200 employees on the road each day, road safety awareness and safe driving are of paramount importance to us; our goal is zero preventable vehicle incidents. Given our expansive asset portfolio across the Appalachian Basin and Central Region, our well tenders and other field employees often spend a significant portion of their days driving. We realized a significant improvement in our preventable Motor Vehicle Accident (“MVA”) Rate, defined as the rate of preventable accidents that occurred during the year per million miles driven by our field personnel, in 2022. We are proud of this accomplishment given the 24.5 million miles driven by our employees during the course of the year largely as a result of the often rural and widespread nature of our asset base and the additional staff members that joined the Company from our 2022 acquisitions. The improvement in our MVA rate can be attributed to our widespread emphasis on safety in our operations, including driving, the use of dedicated training modules and our Safe Passages recognition program for drivers who achieve an accident-free driving record during the calendar year.
Reportable Spills
A spill is the introduction into the environment, other than as authorized and whether intentional or unintentional, of a substance that has the potential to cause adverse effects to the environment, human health or infrastructure. A reportable spill is one that must be disclosed to any regulatory agency where we operate. Intensity rate reflects the reportable volume of oil and produced water spills divided by the total gross volume of oil and produced water handled during the period.
The continued expansion of our operating footprint through Central Region acquisitions has resulted in an increased volume of water produced and handled in our operations due to the geological nature of the formations in the Central Region when compared to Appalachia and the higher concentration of unconventional wells. As a result, we experienced a corresponding increase in the absolute volume of reportable spills compared to prior years of operations, which excluded Central Region operations. We aim for zero spills and continue to seek process enhancements, safety procedures and training to manage and reduce the number of spills in the future.
Our exposure to significant spills of liquid products is inherently low given our current production profile of 86% dry natural gas. Nonetheless, we seek to take a rigorous approach to managing any impact of a potential fluid spill and implement practices and processes to minimize or eliminate such spills.
Socio-Economic Contribution
Our community investments are designed to make long-lasting, positive impacts on the communities where we operate and live. We want our actions and economic contributions to make a difference. We start with employing local people to do local work wherever possible, specifically individuals who care about the communities and environments in which they work and live, and that demonstrate passion in how they approach and accomplish their work every day.
We are committed to balancing our business needs with the needs of the communities in which we and our employees operate. In 2022 and throughout 2023, we have continued to develop company-wide programs to enhance our community outreach, including a new grant-giving program and an employee wellness program. In response to our community outreach and engagement work, we have contributed to nearly 140 different organizations that included childhood education, with emphasis on STEM (science, technology, engineering and math), secondary and higher education, children and adult physical and mental health and wellness, environmental stewardship and biodiversity, fine arts for children, food banks and meal programs, homeless shelters, community and volunteer first responders, and local infrastructure.
Our Approach to ESG
Our approach to ESG management encompasses consideration of our climate, environmental and social impacts as well as our responsibility to conduct business in accordance with high standards of
 
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governance. Through our commitment to stakeholder engagement and regular consideration of internal and external feedback, we seek to proactively manage the topics most important to our business and corporate strategy. Our objectives to improve and address these key areas have served as the foundation of our ESG efforts and strategy, informing where progress should be tracked, and new forward-looking targets should be set.
Our ESG programs are bolstered by a unique business model focused on two key environmental stewardship approaches which keep our net zero ambitions at the forefront of our decision-making. First, our operational approach to owned assets centers on investments in improving or restoring production, optimizing the integrity and efficiency of our assets and reducing emissions before safely and permanently retiring those assets at the end of their productive life. Additionally, our approach to new acquisition utilizes intentional consideration of the emissions profile and geographic location of target assets in determining their compatibility with our portfolio and our emissions reduction goals. In doing so, we are able to recognize the immediate accretive benefit of the acquisitions to our emissions profile or to develop a near-term plan to achieve those benefits.
While our current environmental focus is on methane reductions, we also continued work on our marginal abatement cost curve (“MACC”) to help share our Scope 1 and 2 net zero greenhouse gas (“GHG”) emissions goals. Further, we are endeavoring to partner our MACC efforts with a new process aimed at building and maintaining real-time emissions intelligence through our emissions analytics and reporting platform in order to enhance the accuracy and power of predictive analytics related to our emissions, thus offering management potential access to better data and more tools for more informed decision-making.
Though our upstream, midstream and asset retirement business units encompass distinct activities, we view our corporate and individual employee actions through the lens of a single, unified OneDEC approach that drives a culture of operational excellence fostered through the integration of people and the standardization of processes and systems. Our OneDEC approach is an effort centered around supporting and encouraging company-wide initiatives by ensuring alignment of our corporate and ESG initiatives with departmental action supported by financial investment and boots on the ground. Thus, we embed our strategic frameworks, values and stewardship business model in our OneDEC culture to align our organization, our goals and our priorities around continued progress.
We view sustainability through the dual lens of seeking to create long-term value for our stakeholders and to ensure our daily actions contribute to a sustainable environment and planet for society at large. When we align our stewardship-focused business model and OneDEC culture with our commitment to ESG, we are doing so with this dual lens in mind.
At Diversified, we challenge ourselves to consider these topics and more when we effectuate our business model, corporate strategy, ESG commitments, daily operations and risk management practices.
Human Capital Management
As of December 31, 2022, we had 1,582 full-time employees.
We have an experienced and professional workforce and continue to grow rapidly through successful acquisitions and, in doing so, we welcomed approximately 160 new employees in 2022. The vast majority of our employee base consists of production employees, including our upstream and midstream field personnel. All other employee positions, including back office, administrative and executive positions, are production support roles.
As part of a coordinated diversity and engagement strategy within our recruitment processes, we have engaged a number of external agencies across specific geographic areas of focus within our operating footprint in support of driving diversity within the Company. The composition of our employee workforce is a reflection of the employees that we retain from the sellers at the time of acquisitions. When coupled with a total annual turnover rate of approximately 17.6%, our opportunity to further diversify our workforce is somewhat limited. Nonetheless, we seek to generate a diverse candidate pool from which we can identify and hire the most qualified individuals, regardless of gender, to the benefit of the Company and our stakeholders.
 
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Our board of directors currently consists of three females and four males, and our senior management, including our executive committee and its direct reports but excluding the executive director, consisted of 87 employees. Although our board of directors does not currently have any ethnically diverse members, it acknowledges the UK Listing Rules’ requirements of having at least one individual on its board of directors who is from a minority ethnic background, which we are required to comply with by the end of 2023. We intend to add an ethnically diverse member to the board of directors and have engaged a third-party advisor to assist with the search process. The board of directors continues to demonstrate diversity in a wider sense, with directors from the U.S. as well as the UK, bringing a range of domestic and international experience to the board of directors. The board of director’s diverse range of experience and expertise covers not only a wealth of experience of operating in the natural gas and oil industry but also extensive technical, operational, financial, legal and environmental expertise.
Government Regulation
General
Our operations in the United States are subject to various federal, state and local (including county and municipal level) laws and regulations. These laws and regulations cover virtually every aspect of our operations including, among other things: use of public roads; construction of well pads, impoundments, tanks and roads; pooling and unitizations; water withdrawal and procurement for well stimulation purposes; wastewater discharge, well drilling, casing and hydraulic fracturing; stormwater management; well production; well plugging; venting or flaring of natural gas; pipeline construction and the compression and transportation of natural gas and liquids; reclamation and restoration of properties after natural gas and oil operations are completed; handling, storage, transportation and disposal of materials used or generated by natural gas and oil operations; the calculation, reporting and payment of taxes on natural gas and oil production; and gathering of natural gas production. Various governmental permits, authorizations and approvals under these laws and regulations are required for exploration and production as well as midstream operations. These laws and regulations, and the permits, authorizations and approvals issued pursuant to such laws and regulations, are intended to protect, among other things: air quality; ground water and surface water resources, including drinking water supplies; wetlands; waterways; protected plants and wildlife; natural resources; and the health and safety of our employees and the communities in which we operate.
We endeavor to conduct our operations in compliance with all applicable U.S. federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements against a backdrop of variable geologic and seasonal conditions, non-compliance during operations can occur. Certain non-compliance may be expected to result in fines or penalties, but could also result in enforcement actions, additional restrictions on our operations, or make it more difficult for us to obtain necessary permits in the future. The possibility exists that new legislation or regulations may be adopted which could have a significant impact on our operations or on our customers’ ability to use our natural gas, natural gas liquids and oil, and may require us or our customers to change their operations significantly or incur substantial costs.
Environmental Laws
Many of the U.S. laws and regulations referred to above are environmental laws and regulations, which vary according to the jurisdiction in which we conduct our operations. In addition to state or local laws and regulations, our operations are also subject to numerous federal environmental laws and regulations. Below is a discussion of some of the more significant federal laws and regulations applicable to us and our operations.
Clean Air Act
The federal Clean Air Act and corresponding state laws and regulations regulate air emissions primarily through permitting and/or emissions control requirements. This affects natural gas production and processing operations. Various activities in our operations are subject to regulation, including pipeline compression, venting and flaring of natural gas, and hydraulic fracturing and completion processes, as well as fugitive emissions from operations. We obtain permits, typically from state or local authorities, to conduct these
 
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activities. Additionally, we are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. Further, emissions from certain proximate and related sources may need to be aggregated to provide for regulation and permitting of a single, major source. Federal and state governmental agencies continue to investigate the potential for emissions from oil and natural gas activities, and further regulation could increase our cost or temporarily restrict our ability to produce. For instance, in November 2021, the Environmental Protection Agency (“EPA”) proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing and storage segments. In November 2022, the EPA issued supplemental proposed regulations that would strengthen and expand on the regulations proposed in 2021. The public comment period for the proposed supplemental regulations closed in February 2023, and the EPA is in the process of finalizing the regulations. Additionally, the Inflation Reduction Act, which was signed into law in August 2022, included a “methane fee” on natural gas emissions from oil and gas operations based on certain emissions intensity thresholds. The EPA plans to finalize rules related to the methane fee in 2023 and expects the new fees to be imposed beginning with emissions reported for calendar year 2024. The impact of future regulatory and legislative developments, if adopted or enacted, could result in increased compliance costs, increased utility costs, additional operating restrictions on our business and an increase in the cost of products generally. Although such costs may impact our business directly or indirectly by impacting our facilities or operations, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding the additional measures and how they will be implemented.
Clean Water Act
The federal Clean Water Act (“CWA”) and corresponding state laws affect our operations by regulating storm water or other discharges of substances, including pollutants, sediment, and spills and releases of oil, brine and other substances, into surface waters, and in certain instances imposing requirements to dispose of produced wastes and other oil and gas wastes at approved disposal facilities. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers, or a delegated state agency. These permits require regular monitoring and compliance with effluent limitations, and include reporting requirements. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
Endangered Species and Migratory Birds
The Endangered Species Act and related state laws regulations protect plant and animal species that are threatened or endangered. The Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act provides similar protections to migratory birds and bald and golden eagles, respectively. Some of our operations are located in areas that are or may be designated as protected habitats for endangered or threatened species, or in areas where migratory birds or bald and golden eagles are known to exist. Laws and regulations intended to protect threatened and endangered species, migratory birds, or bald and golden eagles could have a seasonal impact on our construction activities and operations. New or additional species that may be identified as requiring protection or consideration could also lead to delays in obtaining permits and/or other restrictions, including operational restrictions.
Safety of Gas Transmission and Gathering Pipelines
Natural gas pipelines serving our operations are subject to regulation by the U.S. Department of Transportation’s PHMSA pursuant to the NGPSA, as amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the PSIA, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and the 2011 Pipeline Safety Act. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas. Additionally, certain states, such as West Virginia, also maintain jurisdiction over intrastate natural gas lines. In October 2019, PHMSA finalized the first of three rules that, collectively, are referred
 
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to as the natural gas “Mega Rule.” The first rule imposed additional safety requirements on natural gas transmission pipelines, including maximum operating pressure and integrity management near HCAs for onshore gas transmission pipelines. PHMSA finalized the second rule extending federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures in November 2021. PHMSA published the final of the three components of the Mega Rule in August 2022, which took effect in May 2023. The final rule applies to onshore gas transmission pipelines, clarifies integrity management regulations, expands corrosion control requirements, mandates inspection after extreme weather events, and updates existing repair criteria for both HCA and non-HCA pipelines. Finally, PHMSA published a Notice of Proposed Rulemaking regarding more stringent gas pipeline leak detection and repair requirements to reduce natural gas emissions on May 18, 2023. The adoption of laws or regulations that apply more comprehensive or stringent safety standards could increase the expenses we incur for gathering service.
Resource Conservation and Recovery Act
The federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws and regulations impose requirements for the management, treatment, storage and disposal of hazardous and non-hazardous wastes, including wastes generated by our operations. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of natural gas and oil are currently regulated under RCRA’s solid (non-hazardous) waste provisions. However, legislation has been proposed from time to time, and various environmental groups have filed lawsuits, that, if successful, could result in the reclassification of certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. A change in the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on the industry as well as on our results of operations and financial position.
Comprehensive Environmental Response, Compensation, and Liability Act
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or “Superfund”) imposes joint and several liability for costs of investigation and remediation, and for natural resource damages without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, so-called potentially responsible parties (“PRP”), include the current and past owners or operators of a site where the release occurred and anyone who disposed, transported, or arranged for the disposal, transportation, or treatment of a hazardous substance found at the site. CERCLA also authorized the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment, and to seek to recover from the PRPs the costs of such action. Many states, including states in which we operate, have adopted comparable state statutes.
Although CERCLA generally exempts “petroleum” from regulation, in the course of our operations we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substances, and may have disposed of these wastes at disposal sites owned and operated by others. We may also be the owner or operator of sites on which hazardous substances have been released. In the event contamination is discovered at a site on which we are or have been an owner or operator, or to which we have sent hazardous substances, we could be jointly and severally liable for the costs of investigation and remediation and natural resource damages. Further, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
Oil Pollution Act
The primary federal law related to oil spill liability is the Oil Pollution Act (“OPA”), which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge. OPA assigns joint and several liability, without regard to fault, to each liable party for
 
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oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.
Regulation of the Sale and Transportation of Natural Gas, NGLs and Oil
The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil and refined products and certain other liquids be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.
Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from regulation by FERC. However, the distinction between federally unregulated gathering facilities and FERC regulated transmission facilities is a fact-based determination, and the classification of facilities is the subject of ongoing litigation. We own certain natural gas pipeline facilities that we believe meet the traditional tests FERC has used to establish a pipeline’s primary function as “gathering,” thus exempting it from the jurisdiction of FERC under the Natural Gas Act.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
FERC regulates the transportation of oil and NGLs on interstate pipelines under the provisions of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate transportation of oil, NGLs and other products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.
Natural gas, NGLs and crude oil prices are currently unregulated, but Congress historically has been active in the area of natural gas, NGLs and crude oil regulation. We cannot predict whether new legislation to regulate sales might be enacted in the future or what effect, if any, any such legislation might have on our operations.
Health and Safety Laws
Our operations are subject to regulation under the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws in some states, all of which regulate health and safety of employees at our operations. Additionally, OSHA’s hazardous communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state laws require that information be maintained about hazardous materials used or produced by our operations and that this information be provided to employees, state and local governments and the public.
Climate Change Laws and Regulations
Climate change continues to be a legislative and regulatory focus. There are a number of proposed and recently-enacted laws and regulations at the international, federal, state, regional and local level that seek to limit greenhouse gas emissions, and such laws and regulations that restrict emissions could increase our costs should the requirements necessitate the installation of new equipment or the purchase of emission allowances. For example, the Inflation Reduction Act, which was signed into law in August 2022, includes a “methane fee” that is expected to be imposed beginning with emissions reported for calendar year 2024.
 
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In addition, the current U.S. administration has proposed more stringent methane pollution limits for new and existing gas and oil operations. These laws and regulations could also impact our customers, including the electric generation industry, making alternative sources of energy more competitive and thereby decreasing demand for the natural gas and oil we produce. Additional regulation could also lead to permitting delays and additional monitoring and administrative requirements, in turn impacting electricity generating operations.
At the international level, President Biden has recommitted the United States to the UN-sponsored “Paris Agreement,” for nations to limit their greenhouse gas emissions through non-binding, individually-determined reduction goals every five years after 2020. In April 2021, President Biden announced a goal of reducing the United States’ emissions by 50 – 52% below 2005 levels by 2030. In November 2021, the international community gathered in Glasgow at the 26th Conference of the Parties to the UN Framework Convention on Climate Change, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide greenhouse gases. In a related gesture, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Such commitments were re-affirmed at the 27th Conference of the Parties in Sharm El Sheikh. Although it is not possible at this time to predict how legislation or new regulations that may be adopted pursuant to the Paris Agreement to address greenhouse gas emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to implement such measures associated with our operations.
In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in natural gas and oil activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global climate change effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
Additionally, the SEC’s proposed climate rule published in March 2022, requiring the disclosure of a range of climate-related risks, is expected to be finalized late 2023. We are currently assessing this rule, and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. Additionally, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.
Finally, it should be noted that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as the increased frequency and severity of storms, floods, droughts and other extreme climatic events. If any such effects were to occur, they could have an adverse effect on our operations.
 
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C.   Organizational Structure
The following table sets out details of the Company’s significant subsidiaries as of November 16, 2023:
Name
​ ​
Country of
incorporation/
Principal place
of business
​ ​
Principal activity
​ ​
Effective interest
and proportion of
equity held
​
Diversified Gas & Oil Corporation ​ ​ United States ​ ​ Oil and natural gas operations ​ ​
100
​
Diversified Production LLC ​ ​ United States ​ ​ Oil and natural gas operations ​ ​
100
​
Diversified Midstream LLC ​ ​ United States ​ ​ Oil and natural gas operations ​ ​
100
​
Diversified Energy Marketing, LLC
​ ​ United States ​ ​ Oil and natural gas operations ​ ​
100
​
Diversified ABS Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified ABS LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Diversified ABS Phase II Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified ABS Phase II LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Diversified ABS Phase III Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified ABS Phase III LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified ABS Phase III Upstream LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Diversified ABS Phase III Midstream LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Diversified ABS Phase IV Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified ABS Phase IV LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Diversified ABS Phase V Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified ABS Phase V LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Diversified ABS Phase V Upstream LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Sooner State Joint ABS Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
51.25
​
Diversified ABS Phase VI Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified ABS Phase VI LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified ABS VI Upstream LLC
​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Oaktree ABS VI Upstream LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
ABS 7 Manager LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
DP Lion Equity Holdco LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
DP Lion HoldCo LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
 
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Name
​ ​
Country of
incorporation/
Principal place
of business
​ ​
Principal activity
​ ​
Effective interest
and proportion of
equity held
​
DP RBL Co LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
DP Legacy Central LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
DP Production Holdings II LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
DGOC Holdings Sub II LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
DP Bluegrass Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
DP Bluegrass LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
BlueStone Natural Resources II, LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Cranberry Pipeline Corporation ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Coalfield Pipeline Company ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
DM Bluebonnet LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
DP Tapstone Energy Holdings, LLC
​ ​ United States ​ ​ Holding company ​ ​
100
​
DP Legacy Tapstone LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Chesapeake Granite Wash Trust ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
50.8
​
TGG Cotton Valley Assets, LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Black Bear Midstream Holdings LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Black Bear Midstream LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Black Bear Liquids LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
Black Bear Liquids Marketing LLC
​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
100
​
DM Pennsylvania Holdco LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified Energy Group LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Diversified Energy Company LLC ​ ​ United States ​ ​ Holding company ​ ​
100
​
Next LVL Energy, LLC ​ ​ United States ​ ​ Plugging company ​ ​
100
​
Splendid Land, LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
55
​
Riverside Land, LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
55
​
Old Faithful Land, LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
55
​
Link Land, LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
55
​
Giant Land, LLC ​ ​ United States ​ ​ Oil and natural gas non-operated assets ​ ​
55
​
 
58
 
D.   Property, Plants and Equipment
Corporate Offices
Our principal executive offices are located at 1600 Corporate Drive, Birmingham, Alabama 35242.
Assets and Operations
We have historically operated within the Appalachian Basin, which covers an area of 185,500 square miles. While the area came to prominence following the discovery of significant shale gas reserves in 2009 in the Utica and Marcellus shales, it has been a major producer of natural gas, NGLs and oil from conventional vertical well development since the late 19th century, making it the oldest producing basin within the United States.
Our asset base is comprised of approximately 77,500 conventional and unconventional, mature, long-life, low decline natural gas and oil producing wells on a gross productive basis. These mature wells benefit from simple and low-cost maintenance operations and require low ongoing capital expenditures. Our well portfolio exhibits an average long-term decline rate of approximately 8.5% and contains certain wells that have an expected life of greater than 50 years. In addition to the upstream assets, our portfolio contains approximately 17,700 miles of natural gas gathering pipelines and a network of compression stations and processing facilities.
The map below shows the geographic locations of our assets as of December 31, 2022.
[MISSING IMAGE: mp_appalachia-4clr.jpg]
 
59
 
[MISSING IMAGE: mp_central-4clr.jpg]
Item 4A.   Unresolved Staff Comments
Not applicable.
Item 5.   Operating and Financial Review and Prospects
The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements as of December 31, 2022 and 2021 and for each of the three years in the period ended December 31, 2022 and the Unaudited Condensed Consolidated Interim Financial Statements as of June 30, 2023 and for the six months ended June 30, 2023 and 2022 and related notes (together, the “historical financial information”). The historical financial information has been included in “Item 18. Financial Statements.” The following discussion should also be read in conjunction with other information relating to our business contained in this registration statement, including “Item 3.D. Risk Factors.”
The Historical Financial Information has been prepared in accordance with IFRS as issued by the International Accounting Standards Board.
The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and involves risks and uncertainties. Our actual results could differ materially from those discussed in these statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this registration statement, particularly in “Item 3.D. Risk Factors.”
A.   Operating Results
Overview
We are an independent energy company engaged in the production, marketing and transportation of natural gas, as well as oil from our complementary onshore upstream and midstream assets, primarily located within the Appalachian and Central Regions of the United States. Our proven business model creates sustainable value in today’s natural gas market by investing in producing assets, reducing emissions and improving asset integrity while generating significant, hedge-protected cash flow. We acquire, optimize, produce, transport and retire natural gas from existing wells, seek to optimally steward the resource already developed by others within our industry, reduce the environmental footprint, and sustain important jobs and tax revenues for many local communities. While most companies in our sector are built to explore for and develop new reserves, we fully exploit existing reserves through our focus on safely and efficiently operating existing wells to maximize their productive lives and economic capabilities, which in turn reduces the industry’s footprint on our planet.
 
60
 
Key Factors Affecting Our Performance
Our financial condition and results of operations have been, and will continue to be, affected by a number of important factors, including the following:
Strategic Acquisitions
We have made, and intend to continue to make, strategic acquisitions to supplement our organic growth, solidify our current market presence and expand into new markets. We have made the following business combinations or asset acquisitions for a total aggregate consideration of $1.4 billion during the six months ended June 30, 2023 and the years ended December 31, 2022, 2021 and 2020, comprised of:
•
March 2023: The Tanos II Assets Acquisition, in which we acquired certain upstream assets and related infrastructure in the Central Region;
​
•
September 2022: The ConocoPhillips Assets Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region
​
•
July 2022: Certain plugging infrastructure in the Appalachian Region;
​
•
May 2022: Certain plugging infrastructure in the Appalachian Region;
​
•
April 2022:
​
•
The East Texas Assets Acquisition, in which we acquired working interests in certain upstream assets and related facilities within the Central Region from a private seller, in conjunction with Oaktree;
​
•
Certain midstream assets, inclusive of a processing facility, in the Central Region that was contiguous to our East Texas assets;
​
•
February 2022: Certain plugging infrastructure in the Appalachian Region;
​
•
December 2021: The Tapstone Acquisition, where we acquired working interests in certain upstream assets, field infrastructure, equipment and facilities within the Central Region in conjunction with Oaktree;
​
•
August 2021: The Tanos Acquisition, in which we acquired working interests in certain upstream assets, field infrastructure, equipment and facilities in the Central Region in conjunction with Oaktree;
​
•
July 2021: The Blackbeard Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region;
​
•
May 2021: The Indigo Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region;
​
•
May 2020: The Carbon Acquisition, in which we acquired certain upstream and midstream assets in the Appalachian Region; and
​
•
May 2020: The EQT Acquisition, in which we acquired upstream assets and related gathering infrastructure in the Appalachian Region.
​
Our strategic acquisitions may affect the comparability of our financial results with prior and subsequent periods. We intend to continue to selectively pursue strategic acquisitions to further strengthen our competitiveness. We will evaluate and execute opportunities that complement and scale our business, optimize our profitability, help us expand into adjacent markets and add new capabilities to our business. The integration of acquisitions also requires dedication of substantial time and resources of management, and we may never fully realize synergies and other benefits that we expect.
Commodity Price Volatility
Changes in commodity prices may affect the value of our natural gas and oil reserves, operating cash flow and Adjusted EBITDA, regardless of our operating performance. It is impossible to accurately predict
 
61
 
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
Announced on July 17, 2023 the sale of undeveloped acres in Oklahoma, within the Company’s Central Region, for net consideration of approximately $16 million.
Announced on September 26, 2023 that we completed the semi-annual borrowing base redetermination of our revolving Credit Facility. The borrowing base under the Credit Facility was increased to $425 million reflective of the addition of certain collateral previously acquired from EQT and certain smaller operators in Appalachia.
Segment Reporting
We are an independent owner and operator of producing natural gas and oil wells with properties located in the states of Tennessee, Kentucky, Virginia, West Virginia, Ohio, Pennsylvania, Oklahoma, Texas and Louisiana. Our strategy is to acquire long-life producing assets, efficiently operate those assets to maximize cash flow, and then to retire assets safely and responsibly at the end of their useful life. Our assets consist of natural gas and oil wells, pipelines and a network of gathering lines and compression facilities that are complementary to our core assets. We acquire and manage these assets in a complementary fashion to vertically integrate and improve margins rather than managing them as separate operations. Accordingly, when determining operating segments under IFRS 8, we identified one operating segment that produces and transports natural gas, NGLs and oil in the United States. Refer to Note 2 in the Notes to the Consolidated Financial Statements and Note 2 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for a description of our segment reporting.
Results of Operations
Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022
The following tables set forth our results of operations for the six months ended June 30, 2023 and 2022. See the below subsection titled “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.
 
62
 
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30,
2023
​ ​
June 30,
2022
​ ​
$ Change
​ ​
% Change
​
Net production ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas (MMcf)
​ ​ ​ ​ 131,868 ​ ​ ​ ​ ​ 127,398 ​ ​ ​ ​ ​ 4,470 ​ ​ ​ ​ ​ 4% ​ ​
NGLs (MBbls)
​ ​ ​ ​ 2,981 ​ ​ ​ ​ ​ 2,601 ​ ​ ​ ​ ​ 380 ​ ​ ​ ​ ​ 15% ​ ​
Oil (MBbls)
​ ​ ​ ​ 738 ​ ​ ​ ​ ​ 786 ​ ​ ​ ​ ​ (48) ​ ​ ​ ​ ​ (6)% ​ ​
Total production (MBoe)
​ ​ ​ ​ 25,697 ​ ​ ​ ​ ​ 24,620 ​ ​ ​ ​ ​ 1,077 ​ ​ ​ ​ ​ 4% ​ ​
Average daily production (Boepd)
​ ​ ​ ​ 141,972 ​ ​ ​ ​ ​ 136,022 ​ ​ ​ ​ ​ 5,950 ​ ​ ​ ​ ​ 4% ​ ​
% Natural gas (Boe basis)
​ ​ ​ ​ 86% ​ ​ ​ ​ ​ 86% ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Average realized sales price ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(excluding impact of derivatives settled in cash) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas (Mcf)
​ ​ ​ $ 2.54 ​ ​ ​ ​ $ 5.71 ​ ​ ​ ​ $ (3.17) ​ ​ ​ ​ ​ (56)% ​ ​
NGLs (Bbls)
​ ​ ​ ​ 22.53 ​ ​ ​ ​ ​ 41.46 ​ ​ ​ ​ ​ (18.93) ​ ​ ​ ​ ​ (46)% ​ ​
Oil (Bbls)
​ ​ ​ ​ 73.57 ​ ​ ​ ​ ​ 100.28 ​ ​ ​ ​ ​ (26.71) ​ ​ ​ ​ ​ (27)% ​ ​
Total (Boe)
​ ​ ​ $ 17.75 ​ ​ ​ ​ $ 37.12 ​ ​ ​ ​ $ (19.37) ​ ​ ​ ​ ​ (52)% ​ ​
Average realized sales price ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(including impact of derivatives settled in cash) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas (Mcf)
​ ​ ​ $ 2.96 ​ ​ ​ ​ $ 2.68 ​ ​ ​ ​ $ 0.28 ​ ​ ​ ​ ​ 10% ​ ​
NGLs (Bbls)
​ ​ ​ ​ 23.39 ​ ​ ​ ​ ​ 16.61 ​ ​ ​ ​ ​ 6.78 ​ ​ ​ ​ ​ 41% ​ ​
Oil (Bbls)
​ ​ ​ ​ 68.44 ​ ​ ​ ​ ​ 76.24 ​ ​ ​ ​ ​ (7.80) ​ ​ ​ ​ ​ (10)% ​ ​
Total (Boe)
​ ​ ​ $ 19.87 ​ ​ ​ ​ $ 18.08 ​ ​ ​ ​ $ 1.79 ​ ​ ​ ​ ​ 10% ​ ​
Revenue (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas
​ ​ ​ $ 334,588 ​ ​ ​ ​ $ 727,152 ​ ​ ​ ​ $ (392,564) ​ ​ ​ ​ ​ (54)% ​ ​
NGLs
​ ​ ​ ​ 67,159 ​ ​ ​ ​ ​ 107,846 ​ ​ ​ ​ ​ (40,687) ​ ​ ​ ​ ​ (38)% ​ ​
Oil
​ ​ ​ ​ 54,294 ​ ​ ​ ​ ​ 78,817 ​ ​ ​ ​ ​ (24,523) ​ ​ ​ ​ ​ (31)% ​ ​
Total commodity revenue
​ ​ ​ $ 456,041 ​ ​ ​ ​ $ 913,815 ​ ​ ​ ​ $ (457,774) ​ ​ ​ ​ ​ (50)% ​ ​
Midstream revenue
​ ​ ​ ​ 16,662 ​ ​ ​ ​ ​ 16,602 ​ ​ ​ ​ ​ 60 ​ ​ ​ ​ ​ —% ​ ​
Other revenue
​ ​ ​ ​ 14,602 ​ ​ ​ ​ ​ 3,111 ​ ​ ​ ​ ​ 11,491 ​ ​ ​ ​ ​ 369% ​ ​
Total revenue
​ ​ ​ $ 487,305 ​ ​ ​ ​ $ 933,528 ​ ​ ​ ​ $ (446,223) ​ ​ ​ ​ ​ (48)% ​ ​
Gain (loss) on derivative settlements ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(in thousands)
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas
​ ​ ​ $ 55,741 ​ ​ ​ ​ $ (385,186) ​ ​ ​ ​ $ 440,927 ​ ​ ​ ​ ​ (114)% ​ ​
NGLs
​ ​ ​ ​ 2,569 ​ ​ ​ ​ ​ (64,654) ​ ​ ​ ​ ​ 67,223 ​ ​ ​ ​ ​ (104)% ​ ​
Oil
​ ​ ​ ​ (3,785) ​ ​ ​ ​ ​ (18,891) ​ ​ ​ ​ ​ 15,106 ​ ​ ​ ​ ​ (80)% ​ ​
Net gain (loss) on commodity derivative settlements(1)
​ ​ ​ $ 54,525 ​ ​ ​ ​ $ (468,731) ​ ​ ​ ​ $ 523,256 ​ ​ ​ ​ ​ (112)% ​ ​
Total Revenue, Inclusive of Settled Hedges
​ ​ ​ $ 541,830 ​ ​ ​ ​ $ 464,797 ​ ​ ​ ​ $ 77,033 ​ ​ ​ ​ ​ 17% ​ ​
Per Boe Metrics ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Average realized sales price ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(including impact of derivatives settled in cash)
​ ​ ​ $ 19.87 ​ ​ ​ ​ $ 18.08 ​ ​ ​ ​ $ 1.79 ​ ​ ​ ​ ​ 10% ​ ​
Other revenue
​ ​ ​ ​ 1.22 ​ ​ ​ ​ ​ 0.80 ​ ​ ​ ​ ​ 0.42 ​ ​ ​ ​ ​ 53% ​ ​
LOE
​ ​ ​ ​ (4.34) ​ ​ ​ ​ ​ (3.32) ​ ​ ​ ​ ​ (1.02) ​ ​ ​ ​ ​ 31% ​ ​
Midstream operating expense
​ ​ ​ ​ (1.34) ​ ​ ​ ​ ​ (1.35) ​ ​ ​ ​ ​ 0.01 ​ ​ ​ ​ ​ (1)% ​ ​
 
63
 
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30,
2023
​ ​
June 30,
2022
​ ​
$ Change
​ ​
% Change
​
Employees, administrative costs and professional services 
​ ​ ​ ​ (1.50) ​ ​ ​ ​ ​ (1.47) ​ ​ ​ ​ ​ (0.03) ​ ​ ​ ​ ​ 2% ​ ​
Production taxes
​ ​ ​ ​ (1.22) ​ ​ ​ ​ ​ (1.37) ​ ​ ​ ​ ​ 0.15 ​ ​ ​ ​ ​ (11)% ​ ​
Transportation expense
​ ​ ​ ​ (1.94) ​ ​ ​ ​ ​ (2.34) ​ ​ ​ ​ ​ 0.40 ​ ​ ​ ​ ​ (17)% ​ ​
Proceeds received for leasehold sales
​ ​ ​ ​ 0.27 ​ ​ ​ ​ ​ 0.06 ​ ​ ​ ​ ​ 0.21 ​ ​ ​ ​ ​ 350% ​ ​
Adjusted EBITDA per Boe
​ ​ ​ ​ 11.02 ​ ​ ​ ​ $ 9.09 ​ ​ ​ ​ $ 1.93 ​ ​ ​ ​ ​ 21% ​ ​
Adjusted EBITDA Margin
​ ​ ​ ​ 52% ​ ​ ​ ​ ​ 48% ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Other financial metrics (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Adjusted EBITDA
​ ​ ​ $ 282,864 ​ ​ ​ ​ $ 223,760 ​ ​ ​ ​ $ 59,104 ​ ​ ​ ​ ​ 26% ​ ​
Operating profit (loss)
​ ​ ​ $ 909,656 ​ ​ ​ ​ $ (1,177,133) ​ ​ ​ ​ $ 2,086,789 ​ ​ ​ ​ ​ (177)% ​ ​
Net income (loss)
​ ​ ​ $ 630,932 ​ ​ ​ ​ $ (935,250) ​ ​ ​ ​ $ 1,566,182 ​ ​ ​ ​ ​ (167)% ​ ​
​
(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.
​
Production, Revenue and Hedging
Total revenue in the six months ended June 30, 2023 of $487 million decreased 48% from $934 million reported for the six months ended June 30, 2022, primarily due to a 52% decrease in the average realized sales price slightly offset by 4% higher production. Including commodity hedge settlement gains of $55 million and losses of $469 million in the six months ended June 30, 2023 and 2022, respectively, Total Revenue, inclusive of settled hedges, increased by 17% to $542 million in the six months ended June 30, 2023 from $465 million in the six months ended June 30, 2022.
During the current year’s low commodity price environment we have benefited from our ability to opportunistically elevate our hedge floor during last year’s elevated commodity market cycle. This enhancement in our weighted-average hedged floor helped drive a $29 million increase in Total Revenue, inclusive of settled hedges. In addition to our pricing uplift, we also generated an additional $36 million in Total Revenue, inclusive of settled hedges, through increases in production. We sold approximately 25,697 MBoe in the six months ended June 30, 2023 versus approximately 24,620 MBoe in the six months ended June 30, 2022. This increase in volumes sold was due to the March 2023 Tanos II acquisition as well as the integration of production from the East Texas and ConocoPhillips acquisitions which occurred in April and September 2022, respectively.
The following table summarizes average commodity prices for the periods presented with Henry Hub on a per Mcf basis and Mont Belvieu and WTI on a per Bbl basis:
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30,
2023
​ ​
June 30,
2022
​ ​
$ Change
​ ​
% Change
​
Henry Hub
​ ​ ​ $ 2.76 ​ ​ ​ ​ $ 6.06 ​ ​ ​ ​ $ (3.30) ​ ​ ​
(54)%
​
Mont Belvieu
​ ​ ​ ​ 34.28 ​ ​ ​ ​ ​ 59.43 ​ ​ ​ ​ ​ (25.15) ​ ​ ​
(42)%
​
WTI
​ ​ ​ ​ 74.96 ​ ​ ​ ​ ​ 99.00 ​ ​ ​ ​ ​ (24.04) ​ ​ ​
(24)%
​
Refer to Note 4 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding acquisitions.
 
64
 
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, 2023 by reflecting the effect of changes in volume and in the underlying prices:
​ ​ ​
Natural Gas
​ ​
NGLs
​ ​
Oil
​ ​
Total
​
​ ​ ​
(in thousands)
​
Commodity revenue for the six months ended June 30, 2022
​ ​ ​ $ 727,152 ​ ​ ​ ​ $ 107,846 ​ ​ ​ ​ $ 78,817 ​ ​ ​ ​ $ 913,815 ​ ​
Volume increase (decrease)
​ ​ ​ ​ 25,524 ​ ​ ​ ​ ​ 15,755 ​ ​ ​ ​ ​ (4,813) ​ ​ ​ ​ ​ 36,466 ​ ​
Price increase (decrease)
​ ​ ​ ​ (418,088) ​ ​ ​ ​ ​ (56,442) ​ ​ ​ ​ ​ (19,710) ​ ​ ​ ​ ​ (494,240) ​ ​
Net increase (decrease)
​ ​ ​ ​ (392,564) ​ ​ ​ ​ ​ (40,687) ​ ​ ​ ​ ​ (24,523) ​ ​ ​ ​ ​ (457,774) ​ ​
Commodity revenue for the six months ended June 30, 2023
​ ​ ​ $ 334,588 ​ ​ ​ ​ $ 67,159 ​ ​ ​ ​ $ 54,294 ​ ​ ​ ​ $ 456,041 ​ ​
To manage our cash flows in a volatile commodity price environment and as required by our SPV-level asset backed securities, we utilize derivative contracts that allow us to fix the per unit sales prices for approximately 80% 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:
​ ​ ​
Six Months Ended June 30, 2023
​
​ ​ ​
Natural Gas
​ ​
NGLs
​ ​
Oil
​ ​
Total Commodity
​
​ ​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​
​ ​ ​
(in thousands, except per unit data)
​
Excluding hedge impact
​ ​ ​ $ 334,588 ​ ​ ​ ​ $ 2.54 ​ ​ ​ ​ $ 67,159 ​ ​ ​ ​ $ 22.53 ​ ​ ​ ​ $ 54,294 ​ ​ ​ ​ $ 73.57 ​ ​ ​ ​ $ 456,041 ​ ​ ​ ​ $ 17.75 ​ ​
Commodity hedge impact
​ ​ ​ ​ 55,741 ​ ​ ​ ​ ​ 0.42 ​ ​ ​ ​ ​ 2,569 ​ ​ ​ ​ ​ 0.86 ​ ​ ​ ​ ​ (3,785) ​ ​ ​ ​ ​ (5.13) ​ ​ ​ ​ ​ 54,525 ​ ​ ​ ​ ​ 2.12 ​ ​
Including hedge impact
​ ​ ​ $ 390,329 ​ ​ ​ ​ $ 2.96 ​ ​ ​ ​ $ 69,728 ​ ​ ​ ​ $ 23.39 ​ ​ ​ ​ $ 50,509 ​ ​ ​ ​ $ 68.44 ​ ​ ​ ​ $ 510,566 ​ ​ ​ ​ $ 19.87 ​ ​
​ ​ ​
Six Months Ended June 30, 2022
​
​ ​ ​
Natural Gas
​ ​
NGLs
​ ​
Oil
​ ​
Total Commodity
​
​ ​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​
​ ​ ​
(in thousands, except per unit data)
​
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 ​ ​
Refer to Note 7 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding derivative financial instruments.
Expenses
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30,
2023
​ ​
Per
Per Boe
​ ​
June 30,
2022
​ ​
Per
Per Boe
​ ​
Total Change
​ ​
Per Boe Change
​
​ ​ ​
$
​ ​
%
​ ​
$
​ ​
%
​
​ ​ ​
(in thousands, except per unit data)
​
LOE(1)
​ ​ ​ $ 111,637 ​ ​ ​ ​ $ 4.34 ​ ​ ​ ​ $ 81,776 ​ ​ ​ ​ $ 3.32 ​ ​ ​ ​ $ 29,861 ​ ​ ​ ​ ​ 37% ​ ​ ​ ​ $ 1.02 ​ ​ ​ ​ ​ 31% ​ ​
Production taxes(2)
​ ​ ​ ​ 31,307 ​ ​ ​ ​ ​ 1.22 ​ ​ ​ ​ ​ 33,878 ​ ​ ​ ​ ​ 1.37 ​ ​ ​ ​ ​ (2,571) ​ ​ ​ ​ ​ (8)% ​ ​ ​ ​ ​ (0.15) ​ ​ ​ ​ ​ (11)% ​ ​
Midstream operating expense(3)
​ ​ ​ ​ 34,391 ​ ​ ​ ​ ​ 1.34 ​ ​ ​ ​ ​ 33,156 ​ ​ ​ ​ ​ 1.35 ​ ​ ​ ​ ​ 1,235 ​ ​ ​ ​ ​ 4% ​ ​ ​ ​ ​ (0.01) ​ ​ ​ ​ ​ (1)% ​ ​
Transportation expense(4)
​ ​ ​ ​ 49,964 ​ ​ ​ ​ ​ 1.94 ​ ​ ​ ​ ​ 57,547 ​ ​ ​ ​ ​ 2.34 ​ ​ ​ ​ ​ (7,583) ​ ​ ​ ​ ​ (13)% ​ ​ ​ ​ ​ (0.40) ​ ​ ​ ​ ​ (17)% ​ ​
Total operating expense
​ ​ ​ $ 227,299 ​ ​ ​ ​ $ 8.84 ​ ​ ​ ​ $ 206,357 ​ ​ ​ ​ $ 8.38 ​ ​ ​ ​ $ 20,942 ​ ​ ​ ​ ​ 10% ​ ​ ​ ​ $ 0.46 ​ ​ ​ ​ ​ 5% ​ ​
 
65
 
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30,
2023
​ ​
Per
Per Boe
​ ​
June 30,
2022
​ ​
Per
Per Boe
​ ​
Total Change
​ ​
Per Boe
Change
​
​ ​ ​
$
​ ​
%
​ ​
$
​ ​
%
​
​ ​ ​
(in thousands, except per unit data)
​
Employees, administrative costs and professional services(5)
​ ​ ​ ​ 38,497 ​ ​ ​ ​ ​ 1.50 ​ ​ ​ ​ ​ 36,245 ​ ​ ​ ​ ​ 1.47 ​ ​ ​ ​ ​ 2,252 ​ ​ ​ ​ ​ 6% ​ ​ ​ ​ ​ 0.03 ​ ​ ​ ​ ​ 2% ​ ​
Costs associated with acquisitions(6)
​ ​ ​ ​ 8,866 ​ ​ ​ ​ ​ 0.35 ​ ​ ​ ​ ​ 6,935 ​ ​ ​ ​ ​ 0.28 ​ ​ ​ ​ ​ 1,931 ​ ​ ​ ​ ​ 28% ​ ​ ​ ​ ​ 0.07 ​ ​ ​ ​ ​ 25% ​ ​
Other adjusting costs(7)
​ ​ ​ ​ 3,376 ​ ​ ​ ​ ​ 0.13 ​ ​ ​ ​ ​ 67,033 ​ ​ ​ ​ ​ 2.72 ​ ​ ​ ​ ​ (63,657) ​ ​ ​ ​ ​ (95)% ​ ​ ​ ​ ​ (2.59) ​ ​ ​ ​ ​ (95)% ​ ​
Non-cash equity compensation(8)
​ ​ ​ ​ 4,417 ​ ​ ​ ​ ​ 0.17 ​ ​ ​ ​ ​ 4,069 ​ ​ ​ ​ ​ 0.17 ​ ​ ​ ​ ​ 348 ​ ​ ​ ​ ​ 9% ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ —% ​ ​
Total operating and G&A expense
​ ​ ​ $ 282,455 ​ ​ ​ ​ $ 10.99 ​ ​ ​ ​ $ 320,639 ​ ​ ​ ​ $ 13.02 ​ ​ ​ ​ $ (38,184) ​ ​ ​ ​ ​ (12)% ​ ​ ​ ​ $ (2.03) ​ ​ ​ ​ ​ (16)% ​ ​
Depreciation, depletion and amortization
​ ​ ​ ​ 115,036 ​ ​ ​ ​ ​ 4.48 ​ ​ ​ ​ ​ 118,480 ​ ​ ​ ​ ​ 4.81 ​ ​ ​ ​ ​ (3,444) ​ ​ ​ ​ ​ (3)% ​ ​ ​ ​ ​ (0.33) ​ ​ ​ ​ ​ (7)% ​ ​
Total expenses
​ ​ ​ $ 397,491 ​ ​ ​ ​ $ 15.47 ​ ​ ​ ​ $ 439,119 ​ ​ ​ ​ $ 17.83 ​ ​ ​ ​ $ (41,628) ​ ​ ​ ​ ​ (9)% ​ ​ ​ ​ $ (2.36) ​ ​ ​ ​ ​ (13)% ​ ​
​
​
(1)
LOE includes costs incurred to maintain producing properties. Such costs include direct and contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.
​
(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 the Company’s natural gas and oil properties and midstream assets.
​
(3)
Midstream operating expenses are daily costs incurred to operate the Company’s 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 the Company’s 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 as well as internal workforce costs directly related to integrating acquisitions into our system.
​
(7)
Other adjusting costs for the six months ended June 30, 2023 primarily consisted of expenses associated with an unused firm transportation agreement and legal and professional fees related to internal audit and financial reporting. Other adjusting costs for the six months ended June 30, 2022 primarily consisted of $28,345 in contract terminations which will allow the Company to obtain more favorable pricing in the future and $31,099 in costs associated with deal breakage and/or sourcing costs for acquisitions.
​
(8)
Non-cash equity compensation reflects the expense recognition related to share-based compensation provided to certain key members of the management team.
​
Operating Expenses
We experienced an increase in per unit operating expense of 5%, or $0.46 per Boe, resulting from:
 
66
 
•
Higher per Boe LOE that rose 31%, or $1.02 per Boe, resulting from increases in costs from the assets acquired in the Central Region, which carry a higher unit cost and revenue per unit of production profile, assets from plugging acquisitions and inflationary pressures;
​
Partially offsetting the per unit increase were decreases due to:
•
Lower per Boe production taxes that declined 11%, or $0.15 per Boe, primarily attributable to a decrease in severance taxes as a result of a decrease in unhedged revenue due to lower commodity prices; and
​
•
Lower per Boe transportation expense that declined 17%, or $0.40 per Boe, primarily related to decreases in commodity price linked components of third-party midstream rates and costs.
​
General and Administrative Expense
G&A expense decreased due to:
•
A decrease in other adjusting costs due to the comparatively limited transactional activity during 2023 when compared to June 30, 2022. From time to time we incur costs associated with potential acquisitions. These costs include deposits, rights of first refusal, 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 such 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 $6 million in 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 realized more favorable pricing over this period. This transaction also positioned us to refinance these assets as part of the ABS IV financing arrangement and allowed us to enhance our liquidity by eliminating the need for a $20 million letter of credit on our Credit Facility. This transaction was classified in other adjusting costs.
​
Partially offsetting the decrease were increases due to:
•
Employees, administrative costs and professional services increased due to investments made in staff and systems to support our enlarged operation. On a per Boe basis, these costs increased 2%, or 0.03 per Boe.
​
•
An increase in costs associated with acquisitions during 2023 when compared to June 30, 2022 was primarily due to costs related to the integration of the Tanos II acquisition, completion of non-core asset sales and the related diligence for each of these transactions.
​
Other Expenses
Depreciation, depletion and amortization (“DD&A”) decreased due to:
•
Lower depletion expense due to an increase in our reserve estimates driven primarily by changes in commodity prices year-over-year.
​
Partially offset by:
•
Higher depreciation expense attributable to an increase of property, plant & equipment resulting from acquisitions and maintenance capital expenditures.
​
Refer to Note 29 in the Notes to the Consolidated Financial Statements and Note 4 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding reserves and acquisitions, respectively.
 
67
 
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
​
​ ​ ​
June 30, 2023
​ ​
June 30, 2022
​ ​
$ Change
​ ​
% Change
​
​ ​ ​
(in thousands)
​
Net gain (loss) on commodity derivatives settlements(1)
​ ​ ​ $ 54,525 ​ ​ ​ ​ $ (468,731) ​ ​ ​ ​ $ 523,256 ​ ​ ​ ​ ​ (112)% ​ ​
Net gain (loss) on interest rate swaps(1)
​ ​ ​ ​ (2,824) ​ ​ ​ ​ ​ 828 ​ ​ ​ ​ ​ (3,652) ​ ​ ​ ​ ​ (441)% ​ ​
Gain (loss) on foreign currency hedges(1)
​ ​ ​ ​ (521) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (521) ​ ​ ​ ​ ​ (100)% ​ ​
Total gain (loss) on settled derivative instruments
​ ​ ​ $ 51,180 ​ ​ ​ ​ $ (467,903) ​ ​ ​ ​ $ 519,083 ​ ​ ​ ​ ​ (111)% ​ ​
Gain (loss) on fair value adjustments of unsettled financial instruments(2)
​ ​ ​ ​ 760,933 ​ ​ ​ ​ ​ (1,205,938) ​ ​ ​ ​ ​ 1,966,871 ​ ​ ​ ​ ​ (163)% ​ ​
Total gain (loss) on derivative financial instruments
​ ​ ​ $ 812,113 ​ ​ ​ ​ $ (1,673,841) ​ ​ ​ ​ $ 2,485,954 ​ ​ ​ ​ ​ (149)% ​ ​
​
(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, 2023, the total gain on derivative financial instruments of $812 million increased by $2,486 million compared to a loss of $1,674 million in the six months ended June 30, 2022. Adjusting our unsettled derivative contracts to their fair values drove a gain of $761 million in the six months ended June 30, 2023, an increase of $1,967 million, when compared to a loss of $1,206 million in the six months ended June 30, 2022. While this gain certainly reflects the decrease 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 addition of ABS VI in October 2022. The percentage of our long-term future production hedged increases with each additional ABS transaction and can extend through the life of the note. While the change in fair value is significant and reflective of lower prices on the forward price curve, we use derivative contracts to insulate our cash flow from commodity price volatility.
For the six months ended June 30, 2023, the total cash gain on settled derivative instruments was $51 million, an increase of $519 million over the six months ended June 30, 2022. The gain on settled derivative instruments relates to lower commodity market prices than those we secured through our derivative contracts. With consistent cash flows central to our strategy, we routinely hedge at levels that, based on our operating and overhead costs, provide a significant Adjusted EBITDA Margin even if it means forgoing potential price upside.
Refer to Note 7 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding derivative financial instruments.
Finance Costs
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30, 2023
​ ​
June 30, 2022
​ ​
$ Change
​ ​
% Change
​
​ ​ ​
(in thousands)
​
Interest expense, net of capitalized and income amounts(1)
​ ​ ​ $ 58,768 ​ ​ ​ ​ $ 33,322 ​ ​ ​ ​ $ 25,446 ​ ​ ​ ​ ​ 76% ​ ​
Amortization of discount and deferred finance costs
​ ​ ​ ​ 8,968 ​ ​ ​ ​ ​ 5,797 ​ ​ ​ ​ ​ 3,171 ​ ​ ​ ​ ​ 55% ​ ​
Other
​ ​ ​ ​ — ​ ​ ​ ​ ​ 43 ​ ​ ​ ​ ​ (43) ​ ​ ​ ​ ​ (100)% ​ ​
Total finance costs
​ ​ ​ $ 67,736 ​ ​ ​ ​ $ 39,162 ​ ​ ​ ​ $ 28,574 ​ ​ ​ ​ ​ 73% ​ ​
 
68
 
​
(1)
Includes payments related to borrowings and leases.
​
For the six months ended June 30, 2023, interest expense of $59 million increased by $25 million compared to $33 million in the six months ended June 30, 2022, primarily due to the increase in borrowings to fund our 2023 acquisitions as well as the incurrence of a full year of interest on borrowings associated with the 2022 acquisitions. Offsetting these borrowing related increases was a decrease in interest expense for repaid principal of $153 million on the ABS Notes and Term Loan I as these borrowings are repaid monthly due to their amortizing structures.
As of June 30, 2023 and 2022, total borrowings were $1,555 million and $1,381 million, respectively. For the period ended June 30, 2023, the weighted average interest rate on borrowings was 6.19% as compared to 5.38% as of June 30, 2022. This increase resulted from a change in the mix of our financing year-over-year as well as the rising interest rate environment. As of June 30, 2023, 82% of our borrowings were in fixed-rate, hedge-protected, amortizing ABS structures as compared to June 30, 2022 when 99% of our borrowings were in fixed-rate structures.
Refer to Notes 4 and 11 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding acquisitions 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
​
​ ​ ​
June 30, 2023
​ ​
June 30, 2022
​ ​
$ Change
​ ​
% Change
​
​ ​ ​
(in thousands)
​
Income (loss) before taxation
​ ​ ​ $ 828,256 ​ ​ ​ ​ $ (1,230,127) ​ ​ ​ ​ $ 2,058,383 ​ ​ ​ ​ ​ (167)% ​ ​
Income tax benefit (expense)
​ ​ ​ ​ (197,324) ​ ​ ​ ​ ​ 294,877 ​ ​ ​ ​ ​ (492,201) ​ ​ ​ ​ ​ (167)% ​ ​
Effective tax rate
​ ​ ​ ​ 23.8% ​ ​ ​ ​ ​ 24.0% ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
The differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30, 2023
​ ​
June 30, 2022
​
​ ​ ​
(in thousands)
​
Expected tax at statutory U.S. federal income tax rate
​ ​ ​ ​ 21.0% ​ ​ ​ ​ ​ 21.0% ​ ​
State income taxes, net of federal tax benefit
​ ​ ​ ​ 3.0% ​ ​ ​ ​ ​ 3.0% ​ ​
Other, net
​ ​ ​ ​ (0.2)% ​ ​ ​ ​ ​ —% ​ ​
Effective tax rate
​ ​ ​ ​ 23.8% ​ ​ ​ ​ ​ 24.0% ​ ​
Income tax benefit (expense) is recognized based on management’s estimate of the weighted average effective annual income tax rate expected for the full financial year. The estimated average annual tax rate used for the six months ended June 30, 2023 was 23.8%, compared to 24.0% for the six months ended June 30, 2022. For the six months ended June 30, 2023, we reported a tax expense of $197 million, a change of $492 million, compared to a benefit of $295 million in 2022 which was a result of the change in the income before taxation. The resulting effective tax rates for the six months ended June 30, 2023 and 2022 were 23.8% and 24.0%, respectively. Refer to the following section for additional information regarding period-over-period changes in income (loss) before taxation.
 
69
 
Operating Profit, Net Income, EPS, and Adjusted EBITDA
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30, 2023
​ ​
June 30, 2022
​ ​
$ Change
​ ​
% Change
​
​ ​ ​
(in thousands, except per unit data)
​
Operating profit (loss)
​ ​ ​ $ 909,656 ​ ​ ​ ​ $ (1,177,133) ​ ​ ​ ​ $ 2,086,789 ​ ​ ​ ​ ​ (177)% ​ ​
Net income (loss)
​ ​ ​ ​ 630,932 ​ ​ ​ ​ ​ (935,250) ​ ​ ​ ​ ​ 1,566,182 ​ ​ ​ ​ ​ (167)% ​ ​
Adjusted EBITDA
​ ​ ​ ​ 282,864 ​ ​ ​ ​ ​ 223,760 ​ ​ ​ ​ ​ 59,104 ​ ​ ​ ​ ​ 26% ​ ​
Earnings (loss) per share – basic
​ ​ ​ $ 0.68 ​ ​ ​ ​ $ (1.10) ​ ​ ​ ​ $ 1.78 ​ ​ ​ ​ ​ (162)% ​ ​
Earnings (loss) per share – diluted
​ ​ ​ $ 0.67 ​ ​ ​ ​ $ (1.10) ​ ​ ​ ​ $ 1.77 ​ ​ ​ ​ ​ (161)% ​ ​
For the six months ended June 30, 2023, we reported net income of $631 million and diluted earnings per share of $0.67 compared to net loss of $935 million and loss per share of $1.10 in 2022, a decrease of 167% and 162%, respectively. We also reported an operating profit of $910 million compared with an operating loss of $1,177 million for the six months ended June 30, 2023 and 2022, respectively. This year-over-year increase in net income was primarily attributable to an increase of $1,967 million in the mark-to-market valuation adjustment to $761 million in 2023 from a $1,206 million loss in 2022.
Additional adjustments for DD&A, interest, and taxes resulted in Adjusted EBITDA of $283 million for the six months ended June 30, 2023 compared to $224 million for the six months ended June 30, 2022, representing an increase of 26%. The increase in this metric is primarily a result of our accretive growth through acquisitions year-over-year.
See the below subsection titled “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.
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 and Year Ended December 31, 2021 Compared to Year Ended December 31, December 31, 2020
The following tables set forth our results of operations for the years ended December 31, 2022, 2021 and 2020. See the below subsection titled “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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Net production ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas (MMcf)
​ ​ ​ ​ 255,597 ​ ​ ​ ​ ​ 234,643 ​ ​ ​ ​ ​ 199,667 ​ ​ ​ ​ ​ 20,954 ​ ​ ​ ​ ​ 9% ​ ​ ​ ​ ​ 34,976 ​ ​ ​ ​ ​ 18% ​ ​
NGLs (MBbls)
​ ​ ​ ​ 5,200 ​ ​ ​ ​ ​ 3,558 ​ ​ ​ ​ ​ 2,843 ​ ​ ​ ​ ​ 1,642 ​ ​ ​ ​ ​ 46% ​ ​ ​ ​ ​ 715 ​ ​ ​ ​ ​ 25% ​ ​
Oil (MBbls)
​ ​ ​ ​ 1,554 ​ ​ ​ ​ ​ 592 ​ ​ ​ ​ ​ 417 ​ ​ ​ ​ ​ 962 ​ ​ ​ ​ ​ 163% ​ ​ ​ ​ ​ 175 ​ ​ ​ ​ ​ 42% ​ ​
Total production (MBoe)
​ ​ ​ ​ 49,354 ​ ​ ​ ​ ​ 43,257 ​ ​ ​ ​ ​ 36,538 ​ ​ ​ ​ ​ 6,097 ​ ​ ​ ​ ​ 14% ​ ​ ​ ​ ​ 6,719 ​ ​ ​ ​ ​ 18% ​ ​
Average daily production (Boepd)
​ ​ ​ ​ 135,216 ​ ​ ​ ​ ​ 118,512 ​ ​ ​ ​ ​ 99,831 ​ ​ ​ ​ ​ 16,704 ​ ​ ​ ​ ​ 14% ​ ​ ​ ​ ​ 18,681 ​ ​ ​ ​ ​ 19% ​ ​
% Natural gas (Boe basis)
​ ​ ​ ​ 86% ​ ​ ​ ​ ​ 90% ​ ​ ​ ​ ​ 91% ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Average realized sales price ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(excluding impact of derivatives
settled in cash)
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas (Mcf)
​ ​ ​ $ 6.04 ​ ​ ​ ​ $ 3.49 ​ ​ ​ ​ $ 1.72 ​ ​ ​ ​ $ 2.55 ​ ​ ​ ​ ​ 73% ​ ​ ​ ​ $ 1.77 ​ ​ ​ ​ ​ 103% ​ ​
NGLs (Bbls)
​ ​ ​ ​ 36.29 ​ ​ ​ ​ ​ 32.53 ​ ​ ​ ​ ​ 8.15 ​ ​ ​ ​ ​ 3.76 ​ ​ ​ ​ ​ 12% ​ ​ ​ ​ ​ 24.38 ​ ​ ​ ​ ​ 299% ​ ​
Oil (Bbls)
​ ​ ​ ​ 89.85 ​ ​ ​ ​ ​ 65.26 ​ ​ ​ ​ ​ 36.12 ​ ​ ​ ​ ​ 24.59 ​ ​ ​ ​ ​ 38% ​ ​ ​ ​ ​ 29.14 ​ ​ ​ ​ ​ 81% ​ ​
Total (Boe)
​ ​ ​ $ 37.95 ​ ​ ​ ​ $ 22.50 ​ ​ ​ ​ $ 10.45 ​ ​ ​ ​ $ 15.45 ​ ​ ​ ​ ​ 69% ​ ​ ​ ​ $ 12.05 ​ ​ ​ ​ ​ 115% ​ ​
 
70
 
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Average realized sales price ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(including impact of derivatives
settled in cash)
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas (Mcf)
​ ​ ​ $ 2.98 ​ ​ ​ ​ $ 2.36 ​ ​ ​ ​ $ 2.33 ​ ​ ​ ​ $ 0.62 ​ ​ ​ ​ ​ 26% ​ ​ ​ ​ $ 0.03 ​ ​ ​ ​ ​ 1% ​ ​
NGLs (Bbls)
​ ​ ​ ​ 19.84 ​ ​ ​ ​ ​ 15.52 ​ ​ ​ ​ ​ 13.95 ​ ​ ​ ​ ​ 4.32 ​ ​ ​ ​ ​ 28% ​ ​ ​ ​ ​ 1.57 ​ ​ ​ ​ ​ 11% ​ ​
Oil (Bbls)
​ ​ ​ ​ 72.00 ​ ​ ​ ​ ​ 71.68 ​ ​ ​ ​ ​ 52.97 ​ ​ ​ ​ ​ 0.32 ​ ​ ​ ​ ​ —% ​ ​ ​ ​ ​ 18.71 ​ ​ ​ ​ ​ 35% ​ ​
Total (Boe)
​ ​ ​ $ 19.80 ​ ​ ​ ​ $ 15.08 ​ ​ ​ ​ $ 14.40 ​ ​ ​ ​ $ 4.72 ​ ​ ​ ​ ​ 31% ​ ​ ​ ​ $ 0.68 ​ ​ ​ ​ ​ 5% ​ ​
Revenue (in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas
​ ​ ​ $ 1,544,658 ​ ​ ​ ​ $ 818,726 ​ ​ ​ ​ $ 343,425 ​ ​ ​ ​ $ 725,932 ​ ​ ​ ​ ​ 89% ​ ​ ​ ​ $ 475,301 ​ ​ ​ ​ ​ 138% ​ ​
NGLs
​ ​ ​ ​ 188,733 ​ ​ ​ ​ ​ 115,747 ​ ​ ​ ​ ​ 23,173 ​ ​ ​ ​ ​ 72,986 ​ ​ ​ ​ ​ 63% ​ ​ ​ ​ ​ 92,574 ​ ​ ​ ​ ​ 399% ​ ​
Oil
​ ​ ​ ​ 139,620 ​ ​ ​ ​ ​ 38,634 ​ ​ ​ ​ ​ 15,064 ​ ​ ​ ​ ​ 100,986 ​ ​ ​ ​ ​ 261% ​ ​ ​ ​ ​ 23,570 ​ ​ ​ ​ ​ 156% ​ ​
Total commodity revenue
​ ​ ​ $ 1,873,011 ​ ​ ​ ​ $ 973,107 ​ ​ ​ ​ $ 381,662 ​ ​ ​ ​ $ 899,904 ​ ​ ​ ​ ​ 92% ​ ​ ​ ​ $ 591,445 ​ ​ ​ ​ ​ 155% ​ ​
Midstream revenue
​ ​ ​ ​ 32,798 ​ ​ ​ ​ ​ 31,988 ​ ​ ​ ​ ​ 25,389 ​ ​ ​ ​ ​ 810 ​ ​ ​ ​ ​ 3% ​ ​ ​ ​ ​ 6,599 ​ ​ ​ ​ ​ 26% ​ ​
Other revenue
​ ​ ​ ​ 13,540 ​ ​ ​ ​ ​ 2,466 ​ ​ ​ ​ ​ 1,642 ​ ​ ​ ​ ​ 11,074 ​ ​ ​ ​ ​ 449% ​ ​ ​ ​ ​ 824 ​ ​ ​ ​ ​ 50% ​ ​
Total revenue
​ ​ ​ $ 1,919,349 ​ ​ ​ ​ $ 1,007,561 ​ ​ ​ ​ $ 408,693 ​ ​ ​ ​ $ 911,788 ​ ​ ​ ​ ​ 90% ​ ​ ​ ​ $ 598,868 ​ ​ ​ ​ ​ 147% ​ ​
Gain (loss) on derivative settlements (in thousands)
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas
​ ​ ​ $ (782,525) ​ ​ ​ ​ $ (263,929) ​ ​ ​ ​ $ 121,077 ​ ​ ​ ​ $ (518,596) ​ ​ ​ ​ ​ 196% ​ ​ ​ ​ $ (385,006) ​ ​ ​ ​ ​ (318)% ​ ​
NGLs
​ ​ ​ ​ (85,549) ​ ​ ​ ​ ​ (60,530) ​ ​ ​ ​ ​ 16,498 ​ ​ ​ ​ ​ (25,019) ​ ​ ​ ​ ​ 41% ​ ​ ​ ​ ​ (77,028) ​ ​ ​ ​ ​ (467)% ​ ​
Oil
​ ​ ​ ​ (27,728) ​ ​ ​ ​ ​ 3,803 ​ ​ ​ ​ ​ 7,025 ​ ​ ​ ​ ​ (31,531) ​ ​ ​ ​ ​ (829)% ​ ​ ​ ​ ​ (3,222) ​ ​ ​ ​ ​ (46)% ​ ​
Net gain (loss) on commodity derivative settlements(1)
​ ​ ​ $ (895,802) ​ ​ ​ ​ $ (320,656) ​ ​ ​ ​ $ 144,600 ​ ​ ​ ​ $ (575,146) ​ ​ ​ ​ ​ 179% ​ ​ ​ ​ $ (465,256) ​ ​ ​ ​ ​ (322)% ​ ​
Total Revenue, inclusive of settled hedges
​ ​ ​ $ 1,023,547 ​ ​ ​ ​ $ 686,905 ​ ​ ​ ​ $ 553,293 ​ ​ ​ ​ $ 336,642 ​ ​ ​ ​ ​ 49% ​ ​ ​ ​ $ 133,612 ​ ​ ​ ​ ​ 24% ​ ​
Per Boe Metrics ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Average realized sales price ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
(including impact of derivatives
settled in cash)
​ ​ ​ $ 19.80 ​ ​ ​ ​ $ 15.08 ​ ​ ​ ​ $ 14.40 ​ ​ ​ ​ $ 4.72 ​ ​ ​ ​ ​ 31% ​ ​ ​ ​ $ 0.68 ​ ​ ​ ​ ​ 5% ​ ​
Other revenue
​ ​ ​ ​ 0.94 ​ ​ ​ ​ ​ 0.80 ​ ​ ​ ​ ​ 0.74 ​ ​ ​ ​ ​ 0.14 ​ ​ ​ ​ ​ 18% ​ ​ ​ ​ ​ 0.06 ​ ​ ​ ​ ​ 8% ​ ​
LOE
​ ​ ​ ​ (3.70) ​ ​ ​ ​ ​ (2.76) ​ ​ ​ ​ ​ (2.53) ​ ​ ​ ​ ​ (0.94) ​ ​ ​ ​ ​ 34% ​ ​ ​ ​ ​ (0.23) ​ ​ ​ ​ ​ 9% ​ ​
Midstream operating expense 
​ ​ ​ ​ (1.44) ​ ​ ​ ​ ​ (1.40) ​ ​ ​ ​ ​ (1.45) ​ ​ ​ ​ ​ (0.04) ​ ​ ​ ​ ​ 3% ​ ​ ​ ​ ​ 0.05 ​ ​ ​ ​ ​ (3)% ​ ​
Employees, administrative costs and professional services
​ ​ ​ ​ (1.56) ​ ​ ​ ​ ​ (1.31) ​ ​ ​ ​ ​ (1.29) ​ ​ ​ ​ ​ (0.25) ​ ​ ​ ​ ​ 19% ​ ​ ​ ​ ​ (0.02) ​ ​ ​ ​ ​ 2% ​ ​
Recurring allowance for credit losses
​ ​ ​ ​ — ​ ​ ​ ​ ​ 0.10 ​ ​ ​ ​ ​ (0.04) ​ ​ ​ ​ ​ (0.10) ​ ​ ​ ​ ​ (100)% ​ ​ ​ ​ ​ 0.14 ​ ​ ​ ​ ​ (350)% ​ ​
Production taxes
​ ​ ​ ​ (1.50) ​ ​ ​ ​ ​ (0.71) ​ ​ ​ ​ ​ (0.38) ​ ​ ​ ​ ​ (0.79) ​ ​ ​ ​ ​ 111% ​ ​ ​ ​ ​ (0.33) ​ ​ ​ ​ ​ 87% ​ ​
Transportation expense
​ ​ ​ ​ (2.39) ​ ​ ​ ​ ​ (1.86) ​ ​ ​ ​ ​ (1.24) ​ ​ ​ ​ ​ (0.53) ​ ​ ​ ​ ​ 28% ​ ​ ​ ​ ​ (0.62) ​ ​ ​ ​ ​ 50% ​ ​
Proceeds received for leasehold sales
​ ​ ​ ​ 0.05 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 0.05 ​ ​ ​ ​ ​ 100% ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ —% ​ ​
Adjusted EBITDA per Boe
​ ​ ​ $ 10.20 ​ ​ ​ ​ $ 7.94 ​ ​ ​ ​ $ 8.21 ​ ​ ​ ​ $ 2.26 ​ ​ ​ ​ ​ 28% ​ ​ ​ ​ $ (0.27) ​ ​ ​ ​ ​ (3)% ​ ​
Adjusted EBITDA Margin
​ ​ ​ ​ 49% ​ ​ ​ ​ ​ 50% ​ ​ ​ ​ ​ 54% ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
​
 
71
 
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Other financial metrics (in thousands)
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Adjusted EBITDA
​ ​ ​ $ 502,954 ​ ​ ​ ​ $ 343,145 ​ ​ ​ ​ $ 300,590 ​ ​ ​ ​ $ 159,809 ​ ​ ​ ​ ​ 47% ​ ​ ​ ​ $ 42,555 ​ ​ ​ ​ ​ 14% ​ ​
Operating profit (loss)
​ ​ ​ $ (671,403) ​ ​ ​ ​ $ (467,064) ​ ​ ​ ​ $ (77,568) ​ ​ ​ ​ $ (204,339) ​ ​ ​ ​ ​ 44% ​ ​ ​ ​ $ (389,496) ​ ​ ​ ​ ​ 502% ​ ​
Net income (loss)
​ ​ ​ $ (620,598) ​ ​ ​ ​ $ (325,206) ​ ​ ​ ​ $ (23,474) ​ ​ ​ ​ $ (295,392) ​ ​ ​ ​ ​ 91% ​ ​ ​ ​ $ (301,732) ​ ​ ​ ​ ​ 1,285% ​ ​
​
​
(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.
​
Production, Revenue and Hedging
2022 vs 2021
Total revenue in the year ended December 31, 2022 of $1,919 million increased 90% from $1,008 million reported for the year ended December 31, 2021, primarily due to a 69% increase in the average realized sales price and 14% higher production. Including commodity hedge settlement losses of $896 million and losses of $321 million in 2022 and 2021, respectively, Total Revenue, inclusive of settled hedges, increased by 49% to $1,024 million in 2022 from $687 million in 2021.
While the elevated commodity price environment experienced in 2022 played a role in our improved revenues on our unhedged production, we primarily benefited in this market through our ability to opportunistically elevate our hedge floor by 22% year-over-year on hedged volumes. This enhancement in our weighted-average hedged floor helped drive a $135 million increase in Total Revenue, inclusive of settled hedges. In addition to our pricing uplift, we also generated an additional $189 million in Total Revenue, inclusive of settled hedges, through increases in production. We sold approximately 49,354 MBoe in 2022 versus approximately 43,257 MBoe in 2021. This increase in volumes sold was due to the integration of a full year of production from the 2021 Central Region acquisitions as well as the East Texas and ConocoPhillips acquisitions which occurred in April and September 2022, respectively.
2021 vs 2020
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 losses of $321 million and gains of $145 million in 2021 and 2020, respectively, Total Revenue, inclusive of settled hedges, increased by 24% to $687 million in 2021 from $553 million in 2020.
Higher average realized sales prices in 2021 contributed $25 million in additional Total Revenue, inclusive of settled hedges, for the year ended December 31, 2021. The majority of the increase in Total Revenue, inclusive of settled 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.
 
72
 
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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Henry Hub
​ ​ ​ $ 6.62 ​ ​ ​ ​ $ 3.84 ​ ​ ​ ​ $ 2.08 ​ ​ ​ ​ $ 2.78 ​ ​ ​ ​ ​ 72% ​ ​ ​ ​ $ 1.76 ​ ​ ​ ​ ​ 85% ​ ​
Mont Belvieu
​ ​ ​ ​ 51.04 ​ ​ ​ ​ ​ 47.49 ​ ​ ​ ​ ​ 21.85 ​ ​ ​ ​ ​ 3.55 ​ ​ ​ ​ ​ 7% ​ ​ ​ ​ ​ 25.64 ​ ​ ​ ​ ​ 117% ​ ​
WTI
​ ​ ​ ​ 93.53 ​ ​ ​ ​ ​ 68.26 ​ ​ ​ ​ ​ 39.61 ​ ​ ​ ​ ​ 25.27 ​ ​ ​ ​ ​ 37% ​ ​ ​ ​ ​ 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) by reflecting the effect of changes in volume and in the underlying prices:
​ ​ ​
Natural Gas
​ ​
NGLs
​ ​
Oil
​ ​
Total
​
​ ​ ​
(In thousands)
​
Commodity revenue for the year ended December 31, 2019
​ ​ ​ $ 384,121 ​ ​ ​ ​ $ 33,685 ​ ​ ​ ​ $ 20,474 ​ ​ ​ ​ $ 438,280 ​ ​
Volume increase (decrease)
​ ​ ​ ​ 76,900 ​ ​ ​ ​ ​ 432 ​ ​ ​ ​ ​ 503 ​ ​ ​ ​ ​ 77,835 ​ ​
Price increase (decrease)
​ ​ ​ ​ (117,596) ​ ​ ​ ​ ​ (10,944) ​ ​ ​ ​ ​ (5,913) ​ ​ ​ ​ ​ (134,453) ​ ​
Net increase (decrease)
​ ​ ​ ​ (40,696) ​ ​ ​ ​ ​ (10,512) ​ ​ ​ ​ ​ (5,410) ​ ​ ​ ​ ​ (56,618) ​ ​
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 ​ ​
Volume increase (decrease)
​ ​ ​ ​ 73,129 ​ ​ ​ ​ ​ 53,414 ​ ​ ​ ​ ​ 62,780 ​ ​ ​ ​ ​ 189,323 ​ ​
Price increase (decrease)
​ ​ ​ ​ 652,803 ​ ​ ​ ​ ​ 19,572 ​ ​ ​ ​ ​ 38,206 ​ ​ ​ ​ ​ 710,581 ​ ​
Net increase (decrease)
​ ​ ​ ​ 725,932 ​ ​ ​ ​ ​ 72,986 ​ ​ ​ ​ ​ 100,986 ​ ​ ​ ​ ​ 899,904 ​ ​
Commodity revenue for the year ended December 31, 2022
​ ​ ​ $ 1,544,658 ​ ​ ​ ​ $ 188,733 ​ ​ ​ ​ $ 139,620 ​ ​ ​ ​ $ 1,873,011 ​ ​
To manage our cash flows in a volatile commodity price environment and as required by our SPV-level asset backed securities, we utilize derivative contracts which allow us to fix the sales prices at a per unit level for approximately 90% of our production to mitigate commodity risk. The tables below set forth the commodity hedge impact on commodity revenue, excluding and including cash received for commodity hedge settlements with natural gas on a per Mcf basis and NGLs and oil on a per Bbl basis:
​ ​ ​
Year Ended December 31, 2022
​
​ ​ ​
Natural Gas
​ ​
NGLs
​ ​
Oil
​ ​
Total Commodity
​
​ ​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​ ​
Revenue
​ ​
Realized $
​
​ ​ ​
(in thousands, except per unit data)
​
Excluding hedge impact
​ ​ ​ $ 1,544,658 ​ ​ ​ ​ $ 6.04 ​ ​ ​ ​ $ 188,733 ​ ​ ​ ​ $ 36.29 ​ ​ ​ ​ $ 139,620 ​ ​ ​ ​ $ 89.85 ​ ​ ​ ​ $ 1,873,011 ​ ​ ​ ​ $ 37.95 ​ ​
Commodity hedge impact
​ ​ ​ ​ (782,525) ​ ​ ​ ​ ​ (3.06) ​ ​ ​ ​ ​ (85,549) ​ ​ ​ ​ ​ (16.45) ​ ​ ​ ​ ​ (27,728) ​ ​ ​ ​ ​ (17.85) ​ ​ ​ ​ ​ (895,802) ​ ​ ​ ​ ​ (18.15) ​ ​
Including hedge impact
​ ​ ​ $ 762,133 ​ ​ ​ ​ $ 2.98 ​ ​ ​ ​ $ 103,184 ​ ​ ​ ​ $ 19.84 ​ ​ ​ ​ $ 111,892 ​ ​ ​ ​ $ 72.00 ​ ​ ​ ​ $ 977,209 ​ ​ ​ ​ $ 19.80 ​ ​
 
73
 
​ ​ ​
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
​ ​ ​
Year Ended
​
(In thousands, except per unit data)
​ ​
December 31,
2022
​ ​
Per Boe
​ ​
December 31,
2021
​ ​
Per Boe
​ ​
December 31,
2020
​ ​
Per Boe
​ ​
Total Change
2022 – 2021
​ ​
Per Boe
Change
2022 – 2021
​ ​
Total
Change
2021 – 2020
​ ​
Per Boe
Change
2021 – 2020
​
​
$
​ ​
%
​ ​
$
​ ​
%
​ ​
$
​ ​
%
​ ​
$
​ ​
%
​
LOE(1)
​ ​ ​ $ 182,817 ​ ​ ​ ​ $ 3.70 ​ ​ ​ ​ $ 119,594 ​ ​ ​ ​ $ 2.76 ​ ​ ​ ​ $ 92,288 ​ ​ ​ ​ $ 2.53 ​ ​ ​ ​ $ 63,223 ​ ​ ​ ​ ​ 53% ​ ​ ​ ​ $ 0.94 ​ ​ ​ ​ ​ 34% ​ ​ ​ ​ $ 27,306 ​ ​ ​ ​ ​ 30% ​ ​ ​ ​ $ 0.23 ​ ​ ​ ​ ​ 9% ​ ​
Production taxes(2)
​ ​ ​ ​ 73,849 ​ ​ ​ ​ ​ 1.50 ​ ​ ​ ​ ​ 30,518 ​ ​ ​ ​ ​ 0.71 ​ ​ ​ ​ ​ 13,705 ​ ​ ​ ​ ​ 0.38 ​ ​ ​ ​ ​ 43,331 ​ ​ ​ ​ ​ 142% ​ ​ ​ ​ ​ 0.79 ​ ​ ​ ​ ​ 111% ​ ​ ​ ​ ​ 16,813 ​ ​ ​ ​ ​ 123% ​ ​ ​ ​ ​ 0.33 ​ ​ ​ ​ ​ 87% ​ ​
Midstream operating expense(3)
​ ​ ​ ​ 71,154 ​ ​ ​ ​ ​ 1.44 ​ ​ ​ ​ ​ 60,481 ​ ​ ​ ​ ​ 1.40 ​ ​ ​ ​ ​ 52,815 ​ ​ ​ ​ ​ 1.45 ​ ​ ​ ​ ​ 10,673 ​ ​ ​ ​ ​ 18% ​ ​ ​ ​ ​ 0.04 ​ ​ ​ ​ ​ 3% ​ ​ ​ ​ ​ 7,666 ​ ​ ​ ​ ​ 15% ​ ​ ​ ​ ​ (0.05) ​ ​ ​ ​ ​ (3)% ​ ​
Transportation expense(4)
​ ​ ​ ​ 118,073 ​ ​ ​ ​ ​ 2.39 ​ ​ ​ ​ ​ 80,620 ​ ​ ​ ​ ​ 1.86 ​ ​ ​ ​ ​ 45,155 ​ ​ ​ ​ ​ 1.24 ​ ​ ​ ​ ​ 37,453 ​ ​ ​ ​ ​ 46% ​ ​ ​ ​ ​ 0.53 ​ ​ ​ ​ ​ 28% ​ ​ ​ ​ ​ 35,465 ​ ​ ​ ​ ​ 79% ​ ​ ​ ​ ​ 0.62 ​ ​ ​ ​ ​ 50% ​ ​
Total operating expense
​ ​ ​ $ 445,893 ​ ​ ​ ​ $ 9.03 ​ ​ ​ ​ $ 291,213 ​ ​ ​ ​ $ 6.73 ​ ​ ​ ​ $ 203,963 ​ ​ ​ ​ $ 5.58 ​ ​ ​ ​ $ 154,680 ​ ​ ​ ​ ​ 53% ​ ​ ​ ​ $ 2.30 ​ ​ ​ ​ ​ 34% ​ ​ ​ ​ $ 87,250 ​ ​ ​ ​ ​ 43% ​ ​ ​ ​ $ 1.15 ​ ​ ​ ​ ​ 21% ​ ​
Employees, administrative costs and
professional services(5)
​ ​ ​ ​ 77,172 ​ ​ ​ ​ ​ 1.56 ​ ​ ​ ​ ​ 56,812 ​ ​ ​ ​ ​ 1.31 ​ ​ ​ ​ ​ 47,181 ​ ​ ​ ​ ​ 1.29 ​ ​ ​ ​ ​ 20,360 ​ ​ ​ ​ ​ 36% ​ ​ ​ ​ ​ 0.25 ​ ​ ​ ​ ​ 19% ​ ​ ​ ​ ​ 9,631 ​ ​ ​ ​ ​ 20% ​ ​ ​ ​ ​ 0.02 ​ ​ ​ ​ ​ 2% ​ ​
Costs associated with
acquisitions(6)
​ ​ ​ ​ 15,545 ​ ​ ​ ​ ​ 0.31 ​ ​ ​ ​ ​ 27,743 ​ ​ ​ ​ ​ 0.64 ​ ​ ​ ​ ​ 10,465 ​ ​ ​ ​ ​ 0.29 ​ ​ ​ ​ ​ (12,198) ​ ​ ​ ​ ​ (44)% ​ ​ ​ ​ ​ (0.33) ​ ​ ​ ​ ​ (52)% ​ ​ ​ ​ ​ 17,278 ​ ​ ​ ​ ​ 165% ​ ​ ​ ​ ​ 0.35 ​ ​ ​ ​ ​ 121% ​ ​
Other adjusting costs(7)
​ ​ ​ ​ 69,967 ​ ​ ​ ​ ​ 1.42 ​ ​ ​ ​ ​ 10,371 ​ ​ ​ ​ ​ 0.24 ​ ​ ​ ​ ​ 14,581 ​ ​ ​ ​ ​ 0.40 ​ ​ ​ ​ ​ 59,596 ​ ​ ​ ​ ​ 575% ​ ​ ​ ​ ​ 1.18 ​ ​ ​ ​ ​ 492% ​ ​ ​ ​ ​ (4,210) ​ ​ ​ ​ ​ (29)% ​ ​ ​ ​ ​ (0.16) ​ ​ ​ ​ ​ (40)% ​ ​
Non-cash equity compensation(8)
​ ​ ​ ​ 8,051 ​ ​ ​ ​ ​ 0.16 ​ ​ ​ ​ ​ 7,400 ​ ​ ​ ​ ​ 0.17 ​ ​ ​ ​ ​ 5,007 ​ ​ ​ ​ ​ 0.14 ​ ​ ​ ​ ​ 651 ​ ​ ​ ​ ​ 9% ​ ​ ​ ​ ​ (0.01) ​ ​ ​ ​ ​ (6)% ​ ​ ​ ​ ​ 2,393 ​ ​ ​ ​ ​ 48% ​ ​ ​ ​ ​ 0.03 ​ ​ ​ ​ ​ 21% ​ ​
Total operating and G&A expense
​ ​ ​ $ 616,628 ​ ​ ​ ​ $ 12.48 ​ ​ ​ ​ $ 393,539 ​ ​ ​ ​ $ 9.09 ​ ​ ​ ​ $ 281,197 ​ ​ ​ ​ $ 7.70 ​ ​ ​ ​ $ 223,089 ​ ​ ​ ​ ​ 57% ​ ​ ​ ​ $ 3.39 ​ ​ ​ ​ ​ 37% ​ ​ ​ ​ $ 112,342 ​ ​ ​ ​ ​ 40% ​ ​ ​ ​ $ 1.39 ​ ​ ​ ​ ​ 18% ​ ​
Depreciation, depletion and amortization
​ ​ ​ ​ 222,257 ​ ​ ​ ​ ​ 4.50 ​ ​ ​ ​ ​ 167,644 ​ ​ ​ ​ ​ 3.88 ​ ​ ​ ​ ​ 117,290 ​ ​ ​ ​ ​ 3.21 ​ ​ ​ ​ ​ 54,613 ​ ​ ​ ​ ​ 33% ​ ​ ​ ​ ​ 0.62 ​ ​ ​ ​ ​ 16% ​ ​ ​ ​ ​ 50,354 ​ ​ ​ ​ ​ 43% ​ ​ ​ ​ ​ 0.67 ​ ​ ​ ​ ​ 21% ​ ​
Allowance for credit losses(9)
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (4,265) ​ ​ ​ ​ ​ (0.10) ​ ​ ​ ​ ​ 8,490 ​ ​ ​ ​ ​ 0.24 ​ ​ ​ ​ ​ 4,265 ​ ​ ​ ​ ​ (100)% ​ ​ ​ ​ ​ 0.10 ​ ​ ​ ​ ​ (100)% ​ ​ ​ ​ ​ (12,755) ​ ​ ​ ​ ​ (150)% ​ ​ ​ ​ ​ (0.34) ​ ​ ​ ​ ​ (142)% ​ ​
Total expenses
​ ​ ​ $ 838,885 ​ ​ ​ ​ $ 16.98 ​ ​ ​ ​ $ 556,918 ​ ​ ​ ​ $ 12.87 ​ ​ ​ ​ $ 406,977 ​ ​ ​ ​ $ 11.14 ​ ​ ​ ​ $ 281,967 ​ ​ ​ ​ ​ 51% ​ ​ ​ ​ $ 4.11 ​ ​ ​ ​ ​ 32% ​ ​ ​ ​ $ 149,941 ​ ​ ​ ​ ​ 37% ​ ​ ​ ​ $ 1.73 ​ ​ ​ ​ ​ 16% ​ ​
​
(1)
LOE includes costs incurred to maintain producing properties. Such costs include direct and contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.
​
(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 the Company’s natural gas and oil properties and midstream assets.
​
(3)
Midstream operating expenses are daily costs incurred to operate the Company’s owned midstream assets inclusive of employee and benefit expenses.
​
 
74
 
(4)
Transportation expenses are daily costs incurred from third-party systems to gather, process and transport the Company’s 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 as well as internal workforce costs directly related to integrating acquisitions into our system.
​
(7)
Other adjusting costs include items that affect the comparability of results or that are not indicative of trends in the ongoing business. These costs consist of one time projects, contemplated transactions or financing arrangements, contract terminations, deal breakage and/or sourcing costs for acquisitions, and unused firm transportation.
​
(8)
Non-cash equity compensation reflects the expense recognition related to share-based compensation provided to certain key members of the management team. Refer to Note 17 in the Notes to the Consolidated Financial Statements for additional information regarding non-cash share-based compensation.
​
(9)
Allowance for credit losses consists of the recognition and reversal of credit losses. Refer to Note 14 in the Notes to the Consolidated Financial Statements for additional information regarding credit losses.
​
Operating Expenses
2022 vs 2021
We experienced increases in per unit operating expense of 34%, or $2.30 per Boe, during the year ended December 31, 2022 compared to 2021 resulting from:
•
Higher per Boe LOE that increased 34%, or $0.94 per Boe, reflective of changes in our portfolio mix due to the higher cost structure of the Central Region and our growing presence there. This metric was also impacted by inflationary pressures, importantly however, even with an increase in unit cost, Adjusted EBITDA margins remained near 50% and reflect the higher revenues per unit of production we generated in the Central Region. The timing of changes in the portfolio mix has impacted this metric as well. During 2022 we had a full year of expenses from the acquired Indigo, Blackbeard, Tanos, and Tapstone assets acquired in May, July, August, and December 2021, respectively. In addition, we had additional costs from the East Texas Assets and ConocoPhillips assets acquired in April and September 2022, respectively.
​
•
Higher per Boe production taxes that increased 111%, or $0.79 per Boe, were primarily attributable to an increase in severance taxes as a result of an increase in revenue due to higher commodity prices and sold volumes and an increase in property taxes related to the acquired Central Region assets given the difference in the regulatory environment; and
​
•
Higher per Boe transportation expense resulting from increases in third-party midstream rates and changes in our cost mix year-over-year due to the higher transportation expense profile of the Central Region assets.
​
•
Higher per Boe midstream operating expense that increased 3%, or $0.04 per Boe. This increase was driven by the growth in our midstream operations due to Central Region acquisitions as well as increases in our operating cost due to inflationary pressures.
​
2021 vs 2020
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:
 
75
 
•
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.
General and Administrative Expense
2022 vs 2021
G&A expense increased during the year ended December 31, 2022 compared to 2021 due to:
•
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.
​
•
Periodically, we incur costs associated with potential acquisitions that include deposits, rights of first refusal, option agreement costs and hedging costs incurred in connection with the potential acquisitions. At times, due to changing macro-economic conditions, commodity price volatility and/or findings observed during our deal diligence efforts, we incur expenses of this nature as breakage and/or deal sourcing fees. In 2021, we paid $25 million in costs associated with a potential acquisition and, due to decisions we made in the first quarter of 2022, we terminated the transaction and wrote off $25 million in certain acquisition related costs related to these items. During 2022, we also incurred an additional $6 million in 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 and allowed us to enhance liquidity by eliminating the need for a $20 million letter of credit on our Credit Facility. This transaction was classified in other adjusting costs.
​
Partially offsetting these increases in G&A were decreases in costs during the year ended December 31, 2022 compared to 2021 due to:
•
Lower costs associated with acquisitions during 2022 when compared to 2021, which was primarily due to the timing of acquisitions in 2022 compared to 2021 as well as variability in the extent of integration support needed amongst acquisitions. During 2022, costs consisted of the continued integration of the 2021 Central Region acquisitions, the April 2022 East Texas Assets acquisition, some initial integration costs incurred in connection with the September 2022 ConocoPhillips acquisition as well as expenses for other midstream and asset retirement related transactions. Expenses incurred in 2021 were primarily attributable to the completion of the integration of the Carbon and EQT acquisitions, which were acquired in May 2020, and the integration of the Indigo, Blackbeard, Tanos, and Tapstone acquisitions, which were acquired in 2021.
​
2021 vs 2020
G&A expense increased during the year ended December 31, 2021 compared to 2020 due to:
 
76
 
•
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
2022 vs 2021
DD&A increased during the year ended December 31, 2022 compared to 2021 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 14% increase in production attributable to an increased number of producing wells from acquisitions.
​
Allowance for credit losses decreased during the year ended December 31, 2022 compared to 2021 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.
​
2021 vs 2020
Depreciation, depletion and amortization (“DD&A”) increased during the year ended December 31, 2021 compared to 2020 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 during the year ended December 31, 2021 compared to 2020 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
​
(In thousands)
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Net gain (loss) on commodity
derivatives settlements(1)
​ ​ ​ $ (895,802) ​ ​ ​ ​ $ (320,656) ​ ​ ​ ​ $ 144,600 ​ ​ ​ ​ $ (575,146) ​ ​ ​ ​ ​ 179% ​ ​ ​ ​ $ (465,256) ​ ​ ​ ​ ​ (322)% ​ ​
Net gain (loss) on interest rate swaps(1)
​ ​ ​ ​ (1,434) ​ ​ ​ ​ ​ (530) ​ ​ ​ ​ ​ (202) ​ ​ ​ ​ ​ (904) ​ ​ ​ ​ ​ 171% ​ ​ ​ ​ ​ (328) ​ ​ ​ ​ ​ 162% ​ ​
 
77
 
​ ​ ​
Year Ended
​
(In thousands)
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Gain (loss) on foreign currency hedges(1)
​ ​ ​ ​ — ​ ​ ​ ​ ​ (1,227) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,227 ​ ​ ​ ​ ​ (100)% ​ ​ ​ ​ ​ (1,227) ​ ​ ​ ​ ​ (100)% ​ ​
Total gain (loss) on settled derivative instruments
​ ​ ​ $ (897,236) ​ ​ ​ ​ $ (322,413) ​ ​ ​ ​ $ 144,398 ​ ​ ​ ​ $ (574,823) ​ ​ ​ ​ ​ 178% ​ ​ ​ ​ $ (466,811) ​ ​ ​ ​ ​ (323)% ​ ​
Gain (loss) on fair value adjustments of unsettled financial instruments(2)
​ ​ ​ ​ (861,457) ​ ​ ​ ​ ​ (652,465) ​ ​ ​ ​ ​ (238,795) ​ ​ ​ ​ ​ (208,992) ​ ​ ​ ​ ​ 32% ​ ​ ​ ​ ​ (413,670) ​ ​ ​ ​ ​ 173% ​ ​
Total gain (loss) on derivative financial instruments
​ ​ ​ $ (1,758,693) ​ ​ ​ ​ $ (974,878) ​ ​ ​ ​ $ (94,397) ​ ​ ​ ​ $ (783,815) ​ ​ ​ ​ ​ 80% ​ ​ ​ ​ $ (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.
​
2022 vs 2021
For the year ended December 31, 2022, the total loss on derivative financial instruments of $1,759 million increased by $784 million compared to a loss of $975 million in 2021. Adjusting our unsettled derivative contracts to their fair values drove a loss of $861 million in 2022, an increase of $209 million, when compared to a loss of $652 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 addition of four ABS issuances in 2022 that each contain long dated hedge portfolios that in some cases extend through the life of the note.
For the year ended December 31, 2022, the total cash loss on settled derivative instruments was $897 million, an increase of $575 million over 2021. The loss on settled derivative instruments relates to higher commodity market prices than we secured through our derivative contracts. With consistent cash flows central to our strategy, we routinely hedge at levels that, based on our operating and overhead costs, provide a healthy margin even if it means foregoing potential price upside.
2021 vs 2020
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 relates to higher commodity market prices than we secured through our derivative contracts.
Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional information regarding derivative financial instruments.
Gain on Bargain Purchases
We recorded the following gain on bargain purchases in the Consolidated Statement of Comprehensive Income for the periods presented:
​ ​ ​
Year Ended
​
(In thousands)
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Gain on bargain purchases
​ ​ ​ $ 4,447 ​ ​ ​ ​ $ 58,072 ​ ​ ​ ​ $ 17,172 ​ ​ ​ ​ $ (53,625) ​ ​ ​ ​ ​ (92)% ​ ​ ​ ​ $ 40,900 ​ ​ ​ ​ ​ 238% ​ ​
 
78
 
For the past few years the E&P segment of the broader energy sector has been in a period of transition and rebalancing, thus creating opportunities for healthy companies like ours to acquire high quality assets for less than their fair value. We have established a track record of being disciplined in our bidding to acquire assets that meet our strict asset profile and are accretive to our overall corporate value.
The gain on bargain purchases of $4.4 million recognized in 2022 was primarily a result of measurement period adjustments associated with the 2021 Tapstone Acquisition. 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.
Gain on bargain purchases are not recorded for transactions that are accounted for as an acquisition of assets under IFRS 3, Business Combinations (“IFRS 3”). Rather, the consideration paid is allocated to the assets acquired on a relative fair value basis.
Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information regarding acquisitions and bargain purchase gain.
Finance Costs
​ ​ ​
Year Ended
​
(In thousands)
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Interest expense, net of capitalized and income amounts(1)
​ ​ ​ $ 86,840 ​ ​ ​ ​ $ 42,370 ​ ​ ​ ​ $ 34,391 ​ ​ ​ ​ $ 44,470 ​ ​ ​ ​ ​ 105% ​ ​ ​ ​ $ 7,979 ​ ​ ​ ​ ​ 23% ​ ​
Amortization of discount and deferred finance costs
​ ​ ​ ​ 13,903 ​ ​ ​ ​ ​ 8,191 ​ ​ ​ ​ ​ 8,334 ​ ​ ​ ​ ​ 5,712 ​ ​ ​ ​ ​ 70% ​ ​ ​ ​ ​ (143) ​ ​ ​ ​ ​ (2)% ​ ​
Other
​ ​ ​ ​ 56 ​ ​ ​ ​ ​ 67 ​ ​ ​ ​ ​ 602 ​ ​ ​ ​ ​ (11) ​ ​ ​ ​ ​ (16)% ​ ​ ​ ​ ​ (535) ​ ​ ​ ​ ​ (89)% ​ ​
Total finance costs
​ ​ ​ $ 100,799 ​ ​ ​ ​ $ 50,628 ​ ​ ​ ​ $ 43,327 ​ ​ ​ ​ $ 50,171 ​ ​ ​ ​ ​ 99% ​ ​ ​ ​ $ 7,301 ​ ​ ​ ​ ​ 17% ​ ​
​
(1)
Includes payments related to borrowings and leases.
​
2022 vs 2021
For the year ended December 31, 2022, interest expense of $87 million increased by $44 million compared to $42 million in 2021, primarily due to the increase in borrowings to fund our 2022 acquisitions, incurring a full year of interest on borrowings associated with the 2021 acquisitions and an increase in the weighted-average interest rate on borrowings year-over-year. Offsetting these increases is a decrease in interest expense for repaid principal of $232 million on the ABS Notes and Term Loan I as these borrowings are repaid monthly due to their amortizing structures.
As of December 31, 2022 and 2021, total borrowings were $1,498 million and $1,042 million, respectively. For the period ended December 31, 2022, the weighted-average interest rate on borrowings was 5.51% as compared to 4.33% as of December 31, 2021. This increase resulted from the rising rate environment’s impact on new ABS issuances, as well as a change in the mix of our financing year-over-year. As a result of our four ABS issuances in 2022, 96% of our borrowings now reside in fixed-rate, hedge-protected, amortizing structures as of December 31, 2022 compared to 44% as of December 31, 2021.
2021 vs 2020
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.
 
79
 
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 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 found elsewhere in this registration statement 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:
​ ​ ​
Year Ended
​
(In thousands)
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Income (loss) before
taxation
​ ​ ​ $ (799,502) ​ ​ ​ ​ $ (550,900) ​ ​ ​ ​ $ (136,740) ​ ​ ​ ​ $ (248,602) ​ ​ ​ ​ ​ 45% ​ ​ ​ ​ $ (414,160) ​ ​ ​ ​ ​ 303% ​ ​
Income tax benefit (expense)
​ ​ ​ ​ 178,904 ​ ​ ​ ​ ​ 225,694 ​ ​ ​ ​ ​ 113,266 ​ ​ ​ ​ ​ (46,790) ​ ​ ​ ​ ​ (21)% ​ ​ ​ ​ ​ 112,428 ​ ​ ​ ​ ​ 99% ​ ​
Effective tax rate
​ ​ ​ ​ 22.4% ​ ​ ​ ​ ​ 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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Expected tax at statutory U.S. federal income tax rate
​ ​ ​ ​ 21.0% ​ ​ ​ ​ ​ 21.0% ​ ​ ​ ​ ​ 21.0% ​ ​
State income taxes, net of federal tax benefit
​ ​ ​ ​ 1.2% ​ ​ ​ ​ ​ 4.4% ​ ​ ​ ​ ​ 5.4% ​ ​
Federal credits
​ ​ ​ ​ —% ​ ​ ​ ​ ​ 15.4% ​ ​ ​ ​ ​ 58.8% ​ ​
Other, net
​ ​ ​ ​ 0.2% ​ ​ ​ ​ ​ 0.2% ​ ​ ​ ​ ​ (2.4)% ​ ​
Effective tax rate
​ ​ ​ ​ 22.4% ​ ​ ​ ​ ​ 41.0% ​ ​ ​ ​ ​ 82.8% ​ ​
2022 vs 2021
For the year ended December 31, 2022, we reported a tax benefit of $179 million, a change of $47 million, compared to a benefit of $226 million in 2021 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, 2022 and 2021 were 22.4% and 41.0%, 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.
 
80
 
2021 vs 2020
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 found elsewhere in this registration statement for additional information regarding taxation.
Operating Profit, Net Income, EPS, and Adjusted EBITDA
​ ​ ​
Year Ended
​
(In thousands, except per unit data)
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Operating profit (loss)
​ ​ ​ $ (671,403) ​ ​ ​ ​ $ (467,064) ​ ​ ​ ​ $ (77,568) ​ ​ ​ ​ $ (204,339) ​ ​ ​ ​ ​ 44% ​ ​ ​ ​ $ (389,496) ​ ​ ​ ​ ​ 502% ​ ​
Net income (loss)
​ ​ ​ ​ (620,598) ​ ​ ​ ​ ​ (325,206) ​ ​ ​ ​ ​ (23,474) ​ ​ ​ ​ ​ (295,392) ​ ​ ​ ​ ​ 91% ​ ​ ​ ​ ​ (301,732) ​ ​ ​ ​ ​ 1,285% ​ ​
Adjusted EBITDA
​ ​ ​ ​ 502,954 ​ ​ ​ ​ ​ 343,145 ​ ​ ​ ​ ​ 300,590 ​ ​ ​ ​ ​ 159,809 ​ ​ ​ ​ ​ 47% ​ ​ ​ ​ ​ 42,555 ​ ​ ​ ​ ​ 14% ​ ​
Earnings (loss) per share − basic and diluted
​ ​ ​ $ (0.74) ​ ​ ​ ​ $ (0.41) ​ ​ ​ ​ ​ (0.03) ​ ​ ​ ​ $ (0.33) ​ ​ ​ ​ ​ 80% ​ ​ ​ ​ $ (0.38) ​ ​ ​ ​ ​ 1,267% ​ ​
2022 vs 2021
For the year ended December 31, 2022, we reported a net loss of $621 million and loss per share of $0.74 compared to net loss of $325 million and loss per share of $0.41 in 2021, an increase of 91% and 80%, respectively. We also reported an operating loss of $671 million compared with an operating loss of $467 million for the years ended December 31, 2022 and 2021, respectively. This year-over-year increase in net loss was primarily attributable to increased gross profit of $702 million, offset by $784 million of increased losses on derivatives, $54 million less in bargain purchase gains, $50 million more in interest costs, and $47 million less income tax benefit as compared to 2021.
Excluding the mark-to-market valuation adjustment on long-dated derivative valuations, as well as other customary adjustments, we reported Adjusted EBITDA of $503 million for the year ended December 31, 2022 compared to $343 million for the year ended December 31, 2021, representing an increase of 47% driven by our growth through acquisitions.
2021 vs 2020
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 valuation adjustment to $652 million in 2021 from $239 million in 2020, discussed above.
Excluding the mark-to-market valuation adjustment 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.
 
81
 
See the below subsection titled “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.
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. We use these non-IFRS measures 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 from, 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.
Non-IFRS Financial Measures
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,
2023
​ ​
June 30,
2022
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Net income (loss)
​ ​ ​ $ 630,932 ​ ​ ​ ​ $ (935,250) ​ ​ ​ ​ $ (620,598) ​ ​ ​ ​ $ (325,206) ​ ​ ​ ​ $ (23,474) ​ ​
Finance costs
​ ​ ​ ​ 67,736 ​ ​ ​ ​ ​ 39,162 ​ ​ ​ ​ ​ 100,799 ​ ​ ​ ​ ​ 50,628 ​ ​ ​ ​ ​ 43,327 ​ ​
Accretion of asset retirement obligations
​ ​ ​ ​ 13,991 ​ ​ ​ ​ ​ 14,003 ​ ​ ​ ​ ​ 27,569 ​ ​ ​ ​ ​ 24,396 ​ ​ ​ ​ ​ 15,424 ​ ​
Other (income) expense
​ ​ ​ ​ (327) ​ ​ ​ ​ ​ (171) ​ ​ ​ ​ ​ (269) ​ ​ ​ ​ ​ 8,812 ​ ​ ​ ​ ​ 421 ​ ​
Income tax (benefit) expense
​ ​ ​ ​ 197,324 ​ ​ ​ ​ ​ (294,877) ​ ​ ​ ​ ​ (178,904) ​ ​ ​ ​ ​ (225,694) ​ ​ ​ ​ ​ (113,266) ​ ​
Depreciation, depletion and amortization
​ ​ ​ ​ 115,036 ​ ​ ​ ​ ​ 118,480 ​ ​ ​ ​ ​ 222,257 ​ ​ ​ ​ ​ 167,644 ​ ​ ​ ​ ​ 117,290 ​ ​
Loss on joint and working interest owners receivable
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 6,931 ​ ​
(Gain) loss on bargain purchases
​ ​ ​ ​ — ​ ​ ​ ​ ​ (1,249) ​ ​ ​ ​ ​ (4,447) ​ ​ ​ ​ ​ (58,072) ​ ​ ​ ​ ​ (17,172) ​ ​
(Gain) loss on fair value adjustments of unsettled financial instruments
​ ​ ​ ​ (760,933) ​ ​ ​ ​ ​ 1,205,938 ​ ​ ​ ​ ​ 861,457 ​ ​ ​ ​ ​ 652,465 ​ ​ ​ ​ ​ 238,795 ​ ​
(Gain) loss on natural gas and oil property and equipment(1)
​ ​ ​ ​ (899) ​ ​ ​ ​ ​ 515 ​ ​ ​ ​ ​ 93 ​ ​ ​ ​ ​ 901 ​ ​ ​ ​ ​ 2,059 ​ ​
Costs associated with acquisitions
​ ​ ​ ​ 8,866 ​ ​ ​ ​ ​ 6,935 ​ ​ ​ ​ ​ 15,545 ​ ​ ​ ​ ​ 27,743 ​ ​ ​ ​ ​ 10,465 ​ ​
Other adjusting costs(2)
​ ​ ​ ​ 3,376 ​ ​ ​ ​ ​ 67,033 ​ ​ ​ ​ ​ 69,967 ​ ​ ​ ​ ​ 10,371 ​ ​ ​ ​ ​ 14,581 ​ ​
Non-cash equity compensation
​ ​ ​ ​ 4,417 ​ ​ ​ ​ ​ 4,069 ​ ​ ​ ​ ​ 8,051 ​ ​ ​ ​ ​ 7,400 ​ ​ ​ ​ ​ 5,007 ​ ​
(Gain) loss on foreign currency hedge
​ ​ ​ ​ 521 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,227 ​ ​ ​ ​ ​ — ​ ​
(Gain) loss on interest rate swap
​ ​ ​ ​ 2,824 ​ ​ ​ ​ ​ (828) ​ ​ ​ ​ ​ 1,434 ​ ​ ​ ​ ​ 530 ​ ​ ​ ​ ​ 202 ​ ​
Total adjustments
​ ​ ​ $ (348,068) ​ ​ ​ ​ $ 1,159,010 ​ ​ ​ ​ $ 1,123,552 ​ ​ ​ ​ $ 668,351 ​ ​ ​ ​ $ 324,064 ​ ​
Adjusted EBITDA
​ ​ ​ $ 282,864 ​ ​ ​ ​ $ 223,760 ​ ​ ​ ​ $ 502,954 ​ ​ ​ ​ $ 343,145 ​ ​ ​ ​ $ 300,590 ​ ​
​
(1)
Excludes $6.8 million, $1.6 million and $2.5 million in proceeds received for leasehold sales during the six months ended June 30, 2023 and 2022 and the year ended December 31, 2022, respectively.
​
(2)
Other adjusting costs for the six months ended June 30, 2023 primarily consisted of expenses associated
​
 
82
 
with an unused firm transportation agreement and legal and professional fees related to internal audit and financial reporting. Other adjusting costs for the six months ended June 30, 2022 and the year ended December 31, 2022 primarily consisted of $28 million in contract terminations which may allow the Company to obtain more favorable pricing in the future and $31 million in costs associated with deal breakage and/or sourcing costs for acquisitions. Other adjusting costs for the year ended December 31, 2021 were 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. Other adjusting costs for the year ended December 31, 2020, were 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 Settled Hedges; Adjusted EBITDA Margin
The following table reconciles Total Revenue to Total Revenue, inclusive of settled hedges, to Adjusted EBITDA Margin for the periods presented.
​ ​ ​
Six Months Ended
​ ​
Year Ended
​
(In thousands)
​ ​
June 30,
2023
​ ​
June 30,
2022
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Total revenue
​ ​ ​ $ 487,305 ​ ​ ​ ​ $ 933,528 ​ ​ ​ ​ $ 1,919,349 ​ ​ ​ ​ $ 1,007,561 ​ ​ ​ ​ $ 408,693 ​ ​
Net gain (loss) on commodity derivative
instruments(1)
​ ​ ​ ​ 54,525 ​ ​ ​ ​ ​ (468,731) ​ ​ ​ ​ ​ (895,802) ​ ​ ​ ​ ​ (320,656) ​ ​ ​ ​ ​ 144,600 ​ ​
Total Revenue, inclusive of settled hedges
​ ​ ​ $ 541,830 ​ ​ ​ ​ $ 464,797 ​ ​ ​ ​ $ 1,023,547 ​ ​ ​ ​ $ 686,905 ​ ​ ​ ​ $ 553,293 ​ ​
Adjusted EBITDA
​ ​ ​ $ 282,864 ​ ​ ​ ​ $ 223,760 ​ ​ ​ ​ $ 502,954 ​ ​ ​ ​ $ 343,145 ​ ​ ​ ​ $ 300,590 ​ ​
Adjusted EBITDA Margin(2)
​ ​ ​ ​ 52% ​ ​ ​ ​ ​ 48% ​ ​ ​ ​ ​ 49% ​ ​ ​ ​ ​ 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 settled hedges for each of the periods presented.
​
Free Cash Flow
​ ​ ​
Six Months Ended
​ ​
Year Ended
​
​ ​ ​
June 30,
2023
​ ​
June 30,
2022
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Net cash provided by operating activities
​ ​ ​ $ 172,566 ​ ​ ​ ​ $ 204,987 ​ ​ ​ ​ $ 387,764 ​ ​ ​ ​ $ 320,182 ​ ​ ​ ​ $ 241,710 ​ ​
LESS: Expenditures on natural gas and oil properties and equipment
​ ​ ​ ​ (32,332) ​ ​ ​ ​ ​ (44,539) ​ ​ ​ ​ ​ (86,079) ​ ​ ​ ​ ​ (50,175) ​ ​ ​ ​ ​ (21,947) ​ ​
LESS: Cash paid for interest
​ ​ ​ ​ (59,415) ​ ​ ​ ​ ​ (32,605) ​ ​ ​ ​ ​ (82,936) ​ ​ ​ ​ ​ (41,623) ​ ​ ​ ​ ​ (34,335) ​ ​
Free Cash Flow
​ ​ ​ $ 80,819 ​ ​ ​ ​ $ 127,843 ​ ​ ​ ​ $ 218,749 ​ ​ ​ ​ $ 228,384 ​ ​ ​ ​ $ 185,428 ​ ​
 
83
 
Adjusted Operating Cost per Boe
​ ​ ​
Six Months Ended
​ ​
Year Ended
​
(In thousands)
​ ​
June 30,
2023
​ ​
June 30,
2022
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Total production (MBoe)
​ ​ ​ ​ 25,697 ​ ​ ​ ​ ​ 24,620 ​ ​ ​ ​ ​ 49,354 ​ ​ ​ ​ ​ 43,257 ​ ​ ​ ​ ​ 36,538 ​ ​
Total operating expense
​ ​ ​ $ 227,299 ​ ​ ​ ​ $ 206,357 ​ ​ ​ ​ $ 445,893 ​ ​ ​ ​ $ 291,213 ​ ​ ​ ​ $ 203,963 ​ ​
Employees, administrative costs and professional services
​ ​ ​ ​ 38,497 ​ ​ ​ ​ ​ 36,245 ​ ​ ​ ​ ​ 77,172 ​ ​ ​ ​ ​ 56,812 ​ ​ ​ ​ ​ 47,181 ​ ​
Recurring allowance for credit losses
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (4,265) ​ ​ ​ ​ ​ 1,559 ​ ​
Adjusted Operating Cost
​ ​ ​ $ 265,796 ​ ​ ​ ​ $ 242,602 ​ ​ ​ ​ $ 523,065 ​ ​ ​ ​ $ 343,760 ​ ​ ​ ​ $ 252,703 ​ ​
Adjusted Operating Cost per Boe
​ ​ ​ $ 10.34 ​ ​ ​ ​ $ 9.85 ​ ​ ​ ​ $ 10.60 ​ ​ ​ ​ $ 7.95 ​ ​ ​ ​ $ 6.92 ​ ​
PV-10
​ ​ ​
As of
​
(In thousands)
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
​ ​ ​
SEC Pricing(1)
​
PV-10
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Pre-tax (Non-GAAP)(2)
​ ​ ​ $ 8,825,462 ​ ​ ​ ​ $ 4,037,016 ​ ​ ​ ​ $ 1,086,917 ​ ​
PV of Taxes
​ ​ ​ ​ (2,082,362) ​ ​ ​ ​ ​ (703,925) ​ ​ ​ ​ ​ (81,610) ​ ​
Standardized Measure
​ ​ ​ $ 6,743,100 ​ ​ ​ ​ $ 3,333,091 ​ ​ ​ ​ $ 1,005,307 ​ ​
​
(1)
Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For natural gas volumes, the average Henry Hub spot price of $6.36, $3.60 and $1.99 per MMBtu as of December 31, 2022, 2021 and 2020, respectively, was adjusted for gravity, quality, local conditions, gathering and transportation fees, and distance from market. For NGLs and oil volumes, the average WTI price of $94.14, $66.55 and $39.54 per Bbl as of December 31, 2022, 2021 and 2020, respectively, was similarly adjusted for gravity, quality, local conditions, gathering and transportation, fees and distance from market. All prices are held constant throughout the lives of the properties.
​
(2)
The PV-10 of our proved reserves as of December 31, 2022, 2021 and 2020 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.
​
B.   Liquidity and Capital Resources
Overview
Our principal sources of liquidity are cash generated from operations and available borrowings under our Credit Facility. To minimize interest expense, we use our excess cash flow to reduce borrowings on our Credit Facility and as a result have historically carried little cash on our Consolidated Statement of Financial Position as evidenced by $4 million, $7 million, $13 million and $1 million in cash and cash equivalents as of June 30, 2023, December 31, 2022, 2021 and 2020, respectively.
 
84
 
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 follow-on equity offerings from time to time.
We monitor our working capital to ensure that the levels remain adequate to operate the business with excess liquidity primarily utilized for the repayment of debt or dividends to shareholders. We are regularly evaluating potential ABS financings consistent with our previous ABS Notes financings. 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 below) and our Credit Facility bears a floating rate. Given this mix of borrowings in our portfolio from time to time we use interest rate swaps to prudently balance our exposure to fixed and floating rates. Utilizing this strategy we have worked to mitigate interest rate risk and the rising interest rate environment. Going forward, changes in interest rates will continue to impact the floating rate of interest applicable to 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 asset-backed securitizations, as high inflation may result in a relative increase in the cost of debt capital.
Capital expenditures were $32 million for the six months ended June 30, 2023 compared to $45 million for the six months ended June 30, 2022. This decrease in capital expenditures was primarily driven by the completion of wells in 2022 that were under development by Tapstone at the time we closed that acquisition in 2021. While our March 2023 Tanos II acquisition also contained wells under development at the times of acquisition, the capital expenditures needed for their development during the six months ended June 30, 2023 was less significant than that required during the six months ended June 30, 2022. Capital expenditures were $86 million for the year ended December 31, 2022 compared to $50 million for the year ended December 31, 2021. This increase in capital expenditures was primarily driven by our growth through acquisitions year-over-year and during 2022, including the completion of wells that were under development by Tapstone at the time we closed the Tapstone Acquisition. 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. There were no material commitments for capital expenditures as of or subsequent to June 30, 2023. 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.
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, distributions and planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the natural gas and oil industry and other financial and business factors, some of which are beyond our control. Refer to Notes 13 and 21 in the Notes to the Consolidated Financial Statements and Notes 7 and 11 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding our hedging program to mitigate the risk associated with future cash flow generation and current debt obligations.
 
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Liquidity
The table below represents our liquidity position as of the periods presented:
​ ​ ​
As of
​
(In thousands)
​ ​
June 30,
2023
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Cash
​ ​ ​ $ 4,208 ​ ​ ​ ​ $ 7,329 ​ ​ ​ ​ $ 12,558 ​ ​ ​ ​ $ 1,379 ​ ​
Available borrowings under the Credit Facility(1)(2)(3)(4)
​ ​ ​ ​ 98,640 ​ ​ ​ ​ ​ 183,332 ​ ​ ​ ​ ​ 222,263 ​ ​ ​ ​ ​ 201,556 ​ ​
Liquidity ​ ​ ​ $ 102,848 ​ ​ ​ ​ $ 190,661 ​ ​ ​ ​ $ 234,821 ​ ​ ​ ​ $ 202,935 ​ ​
​
(1)
Represents available borrowings under the Credit Facility of $110 million as of June 30, 2023 less outstanding letters of credit of $11 million as of such date.
​
(2)
Represents available borrowings under the Credit Facility of $194 million as of December 31, 2022 less outstanding letters of credit of $11 million as of such date.
​
(3)
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.
​
(4)
Represents available borrowings under the Credit Facility of $212 million as of December 31, 2022 less outstanding letters of credit of $10 million as of such date.
​
From time to time we enter into financing arrangements which maximize the lending value of our collateral to bolster liquidity. In August 2023, we entered into a credit agreement providing us the ability to borrow up to $135 million in loans and extensions of credit from the lender upon meeting conditions considered customary for agreements of this nature. This credit agreement was canceled in September 2023 in connection with the completion of the semi-annual borrowing base redetermination of our revolving Credit Facility, which increased our borrowing base to $425 million from $375 million. The borrowing base is primarily a function of the value of the natural gas and oil properties that collateralize the lending arrangement.
Debt
Our net debt consisted of the following as of the periods presented:
​ ​ ​
As of
​
(In thousands)
​ ​
June 30,
2023
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Credit Facility
​ ​ ​ $ (265,000) ​ ​ ​ ​ $ (56,000) ​ ​ ​ ​ $ (570,600) ​ ​ ​ ​ $ (213,400) ​ ​
ABS I Notes
​ ​ ​ ​ (111,007) ​ ​ ​ ​ ​ (125,864) ​ ​ ​ ​ ​ (155,266) ​ ​ ​ ​ ​ (180,426) ​ ​
ABS II Notes
​ ​ ​ ​ (136,550) ​ ​ ​ ​ ​ (147,458) ​ ​ ​ ​ ​ (169,320) ​ ​ ​ ​ ​ (191,125) ​ ​
ABS III Notes
​ ​ ​ ​ (295,151) ​ ​ ​ ​ ​ (319,856) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
ABS IV Notes
​ ​ ​ ​ (113,609) ​ ​ ​ ​ ​ (130,144) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
ABS V Notes
​ ​ ​ ​ (329,381) ​ ​ ​ ​ ​ (378,796) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
ABS VI Notes
​ ​ ​ ​ (183,758) ​ ​ ​ ​ ​ (212,446) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Term Loan I
​ ​ ​ ​ (112,433) ​ ​ ​ ​ ​ (120,518) ​ ​ ​ ​ ​ (137,099) ​ ​ ​ ​ ​ (156,805) ​ ​
Other
​ ​ ​ ​ (8,319) ​ ​ ​ ​ ​ (7,084) ​ ​ ​ ​ ​ (9,380) ​ ​ ​ ​ ​ (4,730) ​ ​
Total Debt
​ ​ ​ $ (1,555,208) ​ ​ ​ ​ $ (1,498,166) ​ ​ ​ ​ $ (1,041,665) ​ ​ ​ ​ $ (746,486) ​ ​
Cash
​ ​ ​ ​ 4,208 ​ ​ ​ ​ ​ 7,329 ​ ​ ​ ​ ​ 12,558 ​ ​ ​ ​ ​ 1,379 ​ ​
Restricted cash
​ ​ ​ ​ 41,188 ​ ​ ​ ​ ​ 55,388 ​ ​ ​ ​ ​ 19,102 ​ ​ ​ ​ ​ 20,350 ​ ​
Net Debt
​ ​ ​ $ (1,509,812) ​ ​ ​ ​ $ (1,435,449) ​ ​ ​ ​ $ (1,010,005) ​ ​ ​ ​ $ (724,757) ​ ​
 
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Credit Facility
We maintain 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 2022, we amended and restated the credit agreement governing its Credit Facility. The amendment enhanced the alignment with our stated ESG initiatives by including sustainability performance targets (“SPTs”) similar to those included in the ABS III, IV, V and VI notes, extended the maturity of the Credit Facility to August 2026. In March 2023, we performed a semi-annual redetermination and the borrowing base was resized to $375 million reflective of the Tanos II collateral and changes in commodity pricing. In September 2023, we increased the borrowing base to $425 million.
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 quarterly basis. Available borrowings under the Credit Facility were $99 million as of June 30, 2023 which considers the impact of $11 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. The restricted payment provision governs our ability to make discretionary payments such as dividends, share repurchases, or other discretionary payments. DP RBL Co LLC must comply with the following restricted payments test in order to make discretionary payments (i) leverage is less than 1.5x and borrowing base availability is >25% (ii) leverage is between 1.5x and 2.0x, free cash flow must be positive and borrowing base availability must be >15% (iii) leverage is between 2.0x and 2.5x, free cash flow must be positive and borrowing base availability must be >20% (iv) our restricted payments are restricted when leverage exceeds 2.5x for DP RBL Co LLC.
Additional covenants require DP RBL Co LLC 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, 2023.
The 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 MT CO2e per MMcfe;
​
•
Asset Retirement Performance: The number of wells we successfully retire during any fiscal year; and
​
•
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 Credit Facility for each of these categories are aspirational and represent higher thresholds than we have publicly set for ourself. 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.
 
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Term Loan I
In May 2020, we acquired DP Bluegrass LLC (“Bluegrass”), 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. 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, Blackbeard and Tapstone acquisitions.
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, 2023 and 2022 and the years ended December 31, 2022, 2021 and 2020, we incurred $4 million, $4 million, $9 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, 2023.
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 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, 2023 and 2022 and the years ended December 31, 2022, 2021 and 2020, we incurred $3 million, $4 million, $7 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% rate per annum. The fair value of the ABS I Notes approximates the carrying value as of June 30, 2023. In the event that ABS I has cash flow in excess of the required payments, ABS I is required to pay between 50% to 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with DEC. In particular, (a) with respect to any payment date prior to March 1, 2030, (i) if the debt service coverage ratio (the “DSCR”) 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 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. The ABS II Notes were issued at a 2.775% discount. We used the proceeds of $184 million, net of discount, capital reserve requirement, and debt issuance costs, to pay down our 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, 2023 and 2022 and during the years ended December 31, 2022, 2021 and 2020, we incurred $4 million, $5 million, $9 million, $11 million and $8 million in interest related to the ABS II Notes, respectively. The fair value of the ABS II Notes approximates the carrying value as of June 30, 2023.
In the event that ABS II has cash flow in excess of the required payments, ABS II is required to pay between 50% to 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with DEC. In particular, (a) (i) if the DSCR 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
 
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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 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 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 are secured by certain of our upstream producing, 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, 2023 and 2022 and during the year ended December 31, 2022, we incurred $8 million, $7 million and $15 million in interest related to the ABS III Notes, respectively. The fair value of the ABS III Notes approximates the carrying value as of June 30, 2023.
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 DEC. 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 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 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 DEC 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 note holders in monthly note holder 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 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 are secured by a portion of the upstream producing assets acquired in connection with the Blackbeard Acquisition.
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
 
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ABS IV Notes are payable on a monthly basis. During the six months ended June 30, 2023 and 2022 and during the year ended December 31, 2022, we incurred $3 million, $3 million and $6 million in interest related to the ABS IV Notes, respectively. The fair value of the ABS IV Notes approximates the carrying value as of June 30, 2023.
In the event that ABS IV has cash flow in excess of the required payments, ABS IV 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 DEC. In particular, (a) 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 of such Payment Date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS IV 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 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 IV Notes, the interest payable with respect to the subsequent interest accrual period will increase by five basis points. This score is not dependent on DEC 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 note holders in monthly note holder 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 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, we 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 are secured by a majority of our 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, 2023 and 2022 and the year ended December 31, 2022, we incurred $10 million, $2 million and $14 million in interest related to the ABS V Notes, respectively. The fair value of the ABS V Notes approximates the carrying value as of June 30, 2023.
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 of such payment date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS V 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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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 GHG emissions intensity to 2.85 MT CO2e/MMcfe, and/or (2) a reduction in Scope 1 natural gas emissions intensity to 1.12 MT CO2e/MMcfe. For each of these SPTs that we fail to meet, or fail to 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 its semi-annual or annual report, as determined by the timing of such certification, along with an overall ESG update.
ABS VI Notes
In October 2022, we formed Diversified ABS VI LLC (“ABS VI”), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary, to issue, jointly with Oaktree, BBB+ rated asset-backed securities in an aggregate principal amount of $460 million ($236 million to DEC, before fees, representative of our 51.25% ownership interest in the collateral assets). The ABS VI Notes were issued at a 2.63% discount and are secured primarily by the upstream assets that were jointly acquired with Oaktree in the 2021 Tapstone Acquisition. Similar to the accounting treatment described in Note 3 in the Notes to the Consolidated Financial Statements found elsewhere in this registration statement for acquisitions performed in connection with Oaktree, we recorded our proportionate share of the ABS VI Notes in the Consolidated Statement of Financial Position.
The ABS VI Notes accrue interest at a stated 7.50% rate per annum and have a final maturity date of November 2039 with an amortizing maturity of October 2031. Interest and principal payments on the ABS VI Notes are payable on a monthly basis. During the six months ended June 30, 2023 and the year ended December 31, 2022, we incurred $8 million and $3 million in interest related to the ABS VI Notes, respectively. The fair value of the ABS VI Notes approximates the carrying value as of June 30, 2023.
Based on whether certain performance metrics are achieved, ABS VI 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 the applicable 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 VI is less than 80%, then 100%, else 0%; and (c) if the LTV for ABS VI is greater than 75%, then 100%, else 0%.
In addition, a “second party opinion provider” certified the terms of the ABS VI Notes as being aligned with the framework for sustainability-linked bonds of the 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 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 VI Notes contain two SPTs. We must achieve, and have certified by May 28, 2027 (1) a reduction in Scope 1 and Scope 2 GHG emissions intensity to 2.85 MT CO2e/MMcfe, and/or (2) a reduction in Scope 1 natural gas emissions intensity to 1.12 MT CO2e/MMcfe. For each of these SPTs that we fail to meet, or fail to have certified by an external verifier that we have met, by May 28, 2027, the interest rate payable with respect to the ABS VI 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 under the indenture, we intend to disclose this certification on an annual basis in our semi-annual or annual report, as determined by the timing of such certification, along with an overall ESG update.
 
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Compliance
As of June 30, 2023, we met or were in compliance with all sustainability-linked debt metrics.
Our Capital Expenditure Program
Our strategy to acquire and operate producing assets that generate Adjusted EBITDA Margins of approximately 50% allows us to invest capital back into our operations. In addition, we set goals to achieve “net zero” Scope 1 and Scope 2 emissions by 2040 through new investments aimed at emissions reductions, such as investments in natural gas emissions detection devices and conducting aerial scans of our assets.
The majority of our capital expenditures are focused on our midstream operations, which includes pipelines and compression, while the remaining capital expenditures are focused on production optimization, technology, upstream operations, plugging capacity expansion, fleet, emissions reductions, and when prudent, may include development activities targeted at replacing production. Given our operational focus to acquire and operate mature conventional wells and unconventional wells with a shallow decline rate, we do not incur the same level of large capital expenditures associated with drilling and completion activities that would typically be incurred by other development focused exploration and production companies.
In 2022, we paid an annual dividend of $0.17 per share which represents a 5% increase against 2021, paying an aggregate total of approximately $143 million in dividends during 2022. During the six months ended June 30, 2023 we paid $84 million in dividends, equating to $0.04375 per share.
We have consistently targeted a disciplined leverage profile at or under 2.5 to 1.0 after giving effect to acquisitions and any related financing arrangements. We believe this leverage range is supported by our differentiated business model, namely with long-life, low-decline production providing resilient cash flows, and a strategic financial framework that is bolstered by hedging and amortizing debt instruments. Our weighted-average hedge floor on natural gas production increased from $3.63 per Mcf as of December 31, 2022 to $3.79 per Mcf as of June 30, 2023.
Looking forward, we continue to seek to maximize cash flow. We plan to maintain our hedging strategy and take advantage of market opportunities to raise the floor price of our risk management program. We will seek to retain our strategic advantages in purposeful growth through a disciplined capital expenditure program that continues to secure low-cost financing that supports acquisitive growth while maintaining low leverage and ample liquidity. In addition, we intend to remain proactive in our ESG endeavors by seeking to prioritize future capital allocation for ESG initiatives.
Asset Retirement Obligations
We continue to be proactive and innovative with respect to asset retirement. In 2017, after our LSE IPO, we proactively began to meet with state officials to develop a long-term plan to retire our growing portfolio of long-life wells. Collaborating with the appropriate regulators, we designed our retirement activities to be equitable for all stakeholders with an emphasis on the environment.
During 2021 and 2022 we illustrated our continued emphasis in this area with the establishment of an internal plugging operation providing us greater operation control of asset retirement. During this time we accomplished the following:
•
Expanded asset retirement operations from one team and three rigs at December 31, 2021 to 12 teams and 15 rigs at December 31, 2022 through the successful acquisitions of three Appalachian asset retirement companies, which represent a significant portion of the total asset retirement capacity throughout Appalachia;
​
•
Retired 214 wells, inclusive of our Central Region operations, at a consistent average cost of approximately $23 thousand per well, outpacing calendar year 2021 and 2020 activity when we retired 136 and 92 wells, respectively at the same average annual cost of approximately $23 thousand per well. These retirements were achieved one full year in advance of our stated goal to retire 200 wells per year by year-end 2023; and
​
•
Secured contracts with the states of Ohio, West Virginia and Pennsylvania to use our enhanced asset retirement capacity to manage orphan asset retirement programs and/or participate in the retirement
​
 
92
 
of those state-owned wells on their behalf. We expect these relationships to continue to grow as we further solidify our position as a market leader in asset retirement.
During the six months ended June 30, 2023 we retired 100 Diversified wells, inclusive of the Central Region, at an average cost of approximately $20 to $25 thousand per well. We also retired an additional 87 wells for third party producers. Our asset retirement program reflects our solid commitment to a healthy environment and the surrounding communities, and we anticipate continued investment and innovation in this area.
This growth in our asset retirement capacity provides us with the ability to further integrate our asset retirement operations and generate cost efficiencies across a broader footprint. It will also provide us with the ability to generate additional third-party revenues by providing a suite of services to other production companies which can be utilized to help fund the cost associated with our own asset retirement program. As a result, we aim to obtain a prudent mix of both cost reduction and third-party revenues to maximize the benefits of our internal asset retirement program.
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
​
(In thousands)
​ ​
June 30,
2023
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Balance at beginning of period
​ ​ ​ $ 457,083 ​ ​ ​ ​ $ 525,589 ​ ​ ​ ​ $ 346,124 ​ ​ ​ ​ $ 199,521 ​ ​
Additions(1)
​ ​ ​ ​ 3,241 ​ ​ ​ ​ ​ 24,395 ​ ​ ​ ​ ​ 96,292 ​ ​ ​ ​ ​ 26,995 ​ ​
Accretion
​ ​ ​ ​ 13,991 ​ ​ ​ ​ ​ 27,569 ​ ​ ​ ​ ​ 24,396 ​ ​ ​ ​ ​ 15,424 ​ ​
Asset retirement costs
​ ​ ​ ​ (2,077) ​ ​ ​ ​ ​ (4,889) ​ ​ ​ ​ ​ (2,879) ​ ​ ​ ​ ​ (2,442) ​ ​
Disposals(2)
​ ​ ​ ​ (6,314) ​ ​ ​ ​ ​ (16,779) ​ ​ ​ ​ ​ (16,500) ​ ​ ​ ​ ​ (3,838) ​ ​
Revisions to estimate(3)
​ ​ ​ ​ (12,942) ​ ​ ​ ​ ​ (98,802) ​ ​ ​ ​ ​ 78,156 ​ ​ ​ ​ ​ 110,464 ​ ​
Balance at end of period
​ ​ ​ $ 452,982 ​ ​ ​ ​ $ 457,083 ​ ​ ​ ​ $ 525,589 ​ ​ ​ ​ $ 346,124 ​ ​
Less: Current asset retirement obligations
​ ​ ​ ​ 4,517 ​ ​ ​ ​ ​ 4,529 ​ ​ ​ ​ ​ 3,399 ​ ​ ​ ​ ​ 1,882 ​ ​
Non-current asset retirement obligations
​ ​ ​ $ 448,465 ​ ​ ​ ​ $ 452,554 ​ ​ ​ ​ $ 522,190 ​ ​ ​ ​ $ 344,242 ​ ​
​
(1)
Refer to Note 5 in the Notes to the Consolidated Financial Statements and Note 4 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement 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 Note 5 in the Notes to the Consolidated Financial Statements and Note 4 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding acquisitions and divestitures.
​
(3)
As of June 30, 2023, we performed normal revisions to our asset retirement obligations, which resulted in a $13 million decrease in the liability. This decrease was comprised of a $16 million decrease attributable to a marginally higher discount rate which was offset by an increase of $3 million in cost revisions for our recent experiences. The marginal changes in the discount rate are a result of a decline in bond yield volatility over the first half of the year. As of December 31, 2022, we performed normal revisions to our asset retirement obligations, which resulted in a $99 million decrease in the liability. This decrease was comprised of a $145 million decrease attributable to a higher discount rate. The higher discount rate was a result of macroeconomic factors spurred by the increase in bond yields which have elevated with U.S. treasuries to combat the current inflationary environment. Partially offsetting this decrease was $29 million in cost revisions based on our recent asset retirement experiences and a $16 million timing revision for the acceleration of our retirement plans made possible by the recent asset retirement acquisitions that improve our asset retirement capacity through the growth of our operational capabilities. 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
​
 
93
 
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 our internal asset retirement program and efficiencies gained. As of 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 were as set forth in the tables below as of June 30, 2023 and December 31, 2022. When discounting the obligation, consistent with IFRS guidance, we apply a contingency allowance for annual inflationary cost increases to our current cost expectations and then discount the resulting cash flows using a credit adjusted risk free discount rate resulting in a net discount rate of 3.6% and 3.6%, for the periods indicated, respectively. While the rate is comparatively small to the commonly utilized PV-10 metric in our industry, the impact is significant due to the long-life low-decline nature of our portfolio. Although productive life varies within our well portfolio, presently we expect all of our existing wells to have reached the end of their economic lives and be retired by approximately 2095, consistent with our reserve calculations which were independently evaluated by third-party engineers as of December 31, 2022.
When evaluating our ability to meet our asset retirement obligations we review reserves models which utilize the income approach to determine the expected discounted future net cash flows from estimated reserve quantities. These models determine future revenues associated with production using SEC pricing then consider the costs to produce and develop reserves, as well as the cost of asset retirement at the end of a well’s life. These future net cash flows are discounted using a weighted-average cost of capital of 10% to produce the PV-10 of our reserves. After considering the asset retirement costs in these models, our PV-10 was approximately $8.8 billion, $4.0 billion and $1.1 billion as of December 31, 2022, 2021 and 2020, respectively, illustrating cash flows from our reserves well beyond our retirement obligations.
As of June 30, 2023:
​ ​ ​
Not Later
Than
One Year
​ ​
Later Than
One Year
and Not
Later Than
Five Years
​ ​
Later Than
Five Years
​ ​
Total
​
​ ​ ​
(in thousands)
​
Undiscounted
​ ​ ​ $ 4,517 ​ ​ ​ ​ $ 17,360 ​ ​ ​ ​ $ 1,670,290 ​ ​ ​ ​ $ 1,692,167 ​ ​
Discounted
​ ​ ​ ​ 4,517 ​ ​ ​ ​ ​ 15,080 ​ ​ ​ ​ ​ 433,385 ​ ​ ​ ​ ​ 452,982 ​ ​
As of December 31, 2022:
​ ​ ​
Not Later
Than
One Year
​ ​
Later Than
One Year
and Not
Later Than
Five Years
​ ​
Later Than
Five Years
​ ​
Total
​
​ ​ ​
(in thousands)
​
Undiscounted
​ ​ ​ $ 4,529 ​ ​ ​ ​ $ 19,671 ​ ​ ​ ​ $ 1,673,905 ​ ​ ​ ​ $ 1,698,105 ​ ​
Discounted
​ ​ ​ ​ 4,529 ​ ​ ​ ​ ​ 17,314 ​ ​ ​ ​ ​ 435,240 ​ ​ ​ ​ ​ 457,083 ​ ​
 
94
 
As of December 31, 2021:
​ ​ ​
Not Later
Than
One Year
​ ​
Later Than
One Year
and Not
Later Than
Five Years
​ ​
Later Than
Five Years
​ ​
Total
​
​ ​ ​
(in thousands)
​
Undiscounted
​ ​ ​ $ 3,399 ​ ​ ​ ​ $ 17,210 ​ ​ ​ ​ $ 1,594,853 ​ ​ ​ ​ $ 1,615,462 ​ ​
Discounted
​ ​ ​ ​ 3,399 ​ ​ ​ ​ ​ 13,675 ​ ​ ​ ​ ​ 508,515 ​ ​ ​ ​ ​ 525,589 ​ ​
Cash Flows
Our principal sources of liquidity have historically been cash generated from operating activities. To minimize financing costs, we apply our excess cash flow to reduce borrowings on our Credit Facility. When we acquire assets to grow, we complement our Credit Facility with 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 will also raise equity proceeds through follow-on equity offerings.
We monitor our working capital to ensure that the levels remain adequate to operate the business with excess cash primarily being utilized for the repayment of debt or shareholder distributions. In addition to working capital management, we have a disciplined approach to managing operating costs and allocating capital resources, ensuring that we are generating returns on our capital investments to support the strategic initiatives in our business operations.
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30,
2023
​ ​
June 30,
2022
​ ​
$ Change
​ ​
% Change
​
​ ​ ​
(in thousands)
​
Net cash provided by operating activities
​ ​ ​ $ 172,566 ​ ​ ​ ​ $ 204,987 ​ ​ ​ ​ $ (32,421) ​ ​ ​ ​ ​ (16)% ​ ​
Net cash used in investing activities
​ ​ ​ ​ (250,017) ​ ​ ​ ​ ​ (122,118) ​ ​ ​ ​ ​ (127,899) ​ ​ ​ ​ ​ 105% ​ ​
Net cash provided by financing activities
​ ​ ​ ​ 74,330 ​ ​ ​ ​ ​ 91,915 ​ ​ ​ ​ ​ (17,585) ​ ​ ​ ​ ​ (19)% ​ ​
Net change in cash and cash equivalents
​ ​ ​ $ (3,121) ​ ​ ​ ​ $ 174,784 ​ ​ ​ ​ $ (177,905) ​ ​ ​ ​ ​ (102)% ​ ​
​ ​ ​
Year Ended
​
(In thousands)
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​ ​
$ Change
2022 – 2021
​ ​
% Change
2022 – 2021
​ ​
$ Change
2021 – 2020
​ ​
% Change
2021 – 2020
​
Net cash provided by operating activities
​ ​ ​ $ 387,764 ​ ​ ​ ​ $ 320,182 ​ ​ ​ ​ $ 241,710 ​ ​ ​ ​ $ 67,582 ​ ​ ​ ​ ​ 21% ​ ​ ​ ​ $ 78,472 ​ ​ ​ ​ ​ 32% ​ ​
Net cash used in investing
activities
​ ​ ​ ​ (386,457) ​ ​ ​ ​ ​ (627,712) ​ ​ ​ ​ ​ (245,119) ​ ​ ​ ​ ​ 241,255 ​ ​ ​ ​ ​ (38)% ​ ​ ​ ​ ​ (382,593) ​ ​ ​ ​ ​ 156% ​ ​
Net cash provided by financing activities
​ ​ ​ ​ (6,536) ​ ​ ​ ​ ​ 318,709 ​ ​ ​ ​ ​ 3,127 ​ ​ ​ ​ ​ (325,245) ​ ​ ​ ​ ​ (102)% ​ ​ ​ ​ ​ 315,582 ​ ​ ​ ​ ​ 10,092% ​ ​
Net change in cash and cash equivalents
​ ​ ​ $ (5,229) ​ ​ ​ ​ $ 11,179 ​ ​ ​ ​ $ (282) ​ ​ ​ ​ $ (16,408) ​ ​ ​ ​ ​ (147)% ​ ​ ​ ​ $ 11,461 ​ ​ ​ ​ ​ (4,064)% ​ ​
Net Cash Provided by Operating Activities
For the six months ended June 30, 2023, net cash provided by operating activities of $173 million decreased $32 million, or 16%, when compared to $205 million for the six months ended June 30, 2022. The decrease in net cash provided by operating activities was predominantly attributable to the following:
•
A turnover in our working capital position of $194 million. reflecting the impact of the rapid changes in commodity markets during the post-pandemic era. During the six months ended June 30,
​
 
95
 
2022 commodity pricing was rapidly accelerating allowing us to build a working capital benefit of $92 million. When prices cycled back down in 2023 the build up in working capital began to unwind generating cash outflows of $102 million; and
•
These outflows from working capital turnover were offset in part by a $59 million increase in Adjusted EBITDA as well as declines of $64 million in other adjusting costs during the six months ended June 30, 2023 when compared to the six months ended June 30, 2022. Additionally, our hedge modifications transitioned from an outflow of $7 million to an inflow of $17 million offsetting an additional $24 million in year-over-year working capital turnover.
​
For the year ended December 31, 2022, net cash provided by operating activities of $388 million increased by $68 million, or 21%, when compared to $320 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 settled hedges, which marginally offset the increases in expenses described above. This net increase in Adjusted EBITDA was then offset by the increases in cost associated with acquisitions and hedge optimization payments described in Note 13 of the Notes to the Consolidated Financial Statements found elsewhere in this registration statement; and
​
•
Changes in working capital generated additional cash inflows, driven by increasing accounts payable balances, accrued liability, and distribution in suspense balances. These increases are a function of our period-over-period growth through acquisitions and the higher price environment experienced in 2022.
​
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, 2023, net cash used in investing activities of $250 million increased $128 million, or 105%, from outflows of $122 million for the six months ended June 30, 2022. The change in net cash used in investing activities was primarily attributable to the following:
•
An increase in cash outflows of $161 million for acquisition and divestiture activity resulted in cash outflows associated with acquisitions, net of proceeds from divestitures, of $225 million during the six months ended June 30, 2023, compared to $64 million for the six months ended June 30, 2022. Refer to Note 4 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding acquisitions and divestitures; and
​
•
The increase in cash outflows for acquisition and divestiture activity was offset in part by a $13 million decrease in capital expenditures. Capital expenditures were $32 million for the six months ended June 30, 2023 compared to $45 million for the six months ended June 30, 2022. This decrease in capital expenditures was primarily driven by a decline in development costs year-over-year due to the timing of completion activities.
​
For the year ended December 31, 2022, net cash used in investing activities of $386 million decreased by $241 million, or 38%, from outflows of $628 million in 2021. The change in net cash used in investing activities was primarily attributable to the following:
 
96
 
•
A decrease in cash outflows of $268 million for acquisition and divestiture activity provided cash outflows associated with acquisitions and divestitures was $313 million during the year ended December 31, 2022 when compared to $580 million for the year ended December 31, 2021. Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information regarding acquisitions and divestitures; and
​
•
Capital expenditures were $86 million for the year ended December 31, 2022 compared to $50 million for the year ended December 31, 2021. This increase in capital expenditures is primarily driven by our growth through acquisitions year-over-year.
​
For the year ended December 31, 2021, net cash used in investing activities of $628 million increased by $383 million, or 156%, as compared to $245 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; and
​
•
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.
​
Net Cash Provided by Financing Activities
For the six months ended June 30, 2023, net cash provided by financing activities of $74 million decreased $18 million, or 19%, as compared to $92 million for the six months ended June 30, 2022. This change in net cash provided by financing activities was primarily attributable to the following:
•
Our Credit Facility activity resulted in net proceeds of $209 million for the six months ended June 30, 2023 versus net repayments of $571 million for the six months ended June 30, 2022, with much of the decrease in our Credit Facility borrowings being attributable to the proceeds generated by the ABS notes in 2022;
​
•
Our other borrowing structures generated net repayments of $152 million for the six months ended June 30, 2023, as compared to net proceeds of $908 million for the six months ended June 30, 2022. This is primarily a result of the ABS III, IV, V, and VI issuances in 2022 to being held for a full reporting cycle when compared to 2023;
​
•
An increase of $157 million in proceeds from equity issuances as there were no issuances for the six months ended June 30, 2022;
​
•
An increase of $12 million in dividends paid for the six months ended June 30, 2023 as compared to the six months ended June 30, 2022; and
​
•
An increase of $73 million in hedge modifications as there were no financing-related hedge modifications for the six months ended June 30, 2023 as compared to the six months ended June 30, 2022.
​
For the year ended December 31, 2022, net cash provided by financing activities of $7 million decreased by $325 million, or 102%, as compared to $319 million in 2021. This change in net cash provided by financing activities was primarily attributable to the following:
•
Credit Facility activity resulted in net repayments of $515 million in 2022 versus net proceeds of $357 million in 2021, with much of the increase attributable to the issuance of the ABS III-VI Notes in 2022 which refinanced a portion of our Credit Facility by converting it to fixed rate, hedge protected, amortizing structures;
​
•
Our ABS Notes and the Term Loan I generated net proceeds of $967 million in 2022 which consisted of $1.1 billion in proceeds, net of discounts, debt issuance costs and hedge book modifications, and
​
 
97
 
$232 million in repayments. By comparison our ABS Notes and Term Loan I had net repayments of $67 million in 2021 with no comparative new issuances;
•
A decrease of $214 million in proceeds from equity issuances since we did not issue new equity in 2022;
​
•
An increase of $13 million in dividends paid in 2022 as compared to 2021;
​
•
An increase of $35 million in the repurchase of shares, inclusive of EBT repurchases, as there were no similar repurchases in 2021; and
​
•
Restricted cash outflows increased by $38 million year-over-year as a result of the establishment of the interest reserve required by our ABS III — VI Notes that were issued in 2022. No similar notes were issued in 2021.
​
For the year ended December 31, 2021, net cash provided by financing activities of $319 million increased by $316 million, or 10,092%, as compared to $3 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;
​
•
A decrease of $16 million in the repurchase of shares as we did not repurchase any shares in 2021; 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.
​
Refer to Notes 13, 16, 18 and 21 in the Notes to the Consolidated Financial Statements and Notes 7, 8, 9 and 11 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement 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, 2023 and December 31, 2022, our material off-balance sheet arrangements and transactions include operating service arrangements and $11 million and $11 million in letters of credit outstanding against our Credit Facility, respectively. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of capital resources.
 
98
 
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 June 30, 2023 were as follows:
​ ​ ​
Not Later
Than
One Year
​ ​
Later Than
One Year
and Not
Later Than
Five Years
​ ​
Later Than
Five Years
​ ​
Total
​
​ ​ ​
(in thousands)
​
Recorded contractual obligations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Trade and other payables
​ ​ ​ $ 69,744 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ 69,744 ​ ​
Borrowings
​ ​ ​ ​ 231,819 ​ ​ ​ ​ ​ 972,846 ​ ​ ​ ​ ​ 350,543 ​ ​ ​ ​ ​ 1,555,208 ​ ​
Leases
​ ​ ​ ​ 10,645 ​ ​ ​ ​ ​ 22,663 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 33,308 ​ ​
Asset retirement obligation(1)
​ ​ ​ ​ 4,517 ​ ​ ​ ​ ​ 17,360 ​ ​ ​ ​ ​ 1,670,290 ​ ​ ​ ​ ​ 1,692,167 ​ ​
Other liabilities(2)
​ ​ ​ ​ 158,045 ​ ​ ​ ​ ​ 936 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 158,981 ​ ​
Off-Balance Sheet contractual obligations
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Firm Transportation
​ ​ ​ ​ 31,599 ​ ​ ​ ​ ​ 36,025 ​ ​ ​ ​ ​ 176,464 ​ ​ ​ ​ ​ 244,088 ​ ​
Total ​ ​ ​ $ 506,369 ​ ​ ​ ​ $ 1,049,830 ​ ​ ​ ​ $ 2,197,297 ​ ​ ​ ​ $ 3,753,496 ​ ​
​
(1)
Represents our asset retirement obligation on an undiscounted basis. On a discounted basis the liability is $453 million as of June 30, 2023 as presented on the Condensed Consolidated Statement of Financial Position.
​
(2)
Represents accrued expenses and net revenue clearing. 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.
​
We believe that our cash flows from operations and existing liquidity will be sufficient to meet our existing contractual obligations and commitments for at least the next 12 months. Cash flows from operations were $173 million for the six months ended June 30, 2023, which includes only partial-year contributions from our Tanos II acquisition in 2023. Cash flows from operations were $388 million for the year ended December 31, 2022, which includes only partial-year contributions from our acquisitions in 2022. As of June 30, 2023 and December 31, 2022, we had current assets of $339 million and $354 million, respectively, and available borrowings on our Credit Facility of $99 million and $183 million, respectively, (excluding $11 million and $11 million in outstanding letters of credit, respectively), which could also be used to service our contractual obligations and commitments over the next 12 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, individually or in the aggregate, is 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 laws and regulation in all the jurisdictions in which we operate. 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 or regulation once implemented.
 
99
 
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 Program and Climate and Clean Air Coalition in partnership with the European Commission, the UK Government, Environmental Defense Fund and other leading natural gas and oil 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 the “Gold Standard Pathway” for our implementation plan whereby we seek to improve our current measurement processes for natural gas emissions. We expect the impact on our operations to be improved efficiency and reduced emissions.
Recently Issued Accounting Pronouncements
Refer to Note 3 in the Notes to the Consolidated Financial Statements found elsewhere in this registration statement 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 and Note 3 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for information regarding our significant accounting policies, judgments 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. Our borrowings primarily consist of fixed-rate amortizing notes and our variable rate Credit Facility as illustrated below.
​ ​ ​
June 30, 2023
​ ​
December 31, 2022
​ ​
December 31, 2021
​
(In thousands)
​ ​
Borrowings
​ ​
Interest
Rate(1)
​ ​
Borrowings
​ ​
Interest
Rate(1)
​ ​
Borrowings
​ ​
Interest
Rate(1)
​
ABS Notes and Term Loan I
​ ​ ​ $ 1,281,889 ​ ​ ​ ​ ​ 5.68% ​ ​ ​ ​ $ 1,435,082 ​ ​ ​ ​ ​ 5.70% ​ ​ ​ ​ $ 461,685 ​ ​ ​ ​ ​ 5.54% ​ ​
Credit Facility
​ ​ ​ $ 265,000 ​ ​ ​ ​ ​ 8.65% ​ ​ ​ ​ $ 56,000 ​ ​ ​ ​ ​ 7.42% ​ ​ ​ ​ $ 570,600 ​ ​ ​ ​ ​ 3.50% ​ ​
 
100
 
​
(1)
The interest rate on the ABS Notes and Term Loan I borrowings represents the weighted-average fixed-rate of the notes while the interest rate presented for the Credit Facility represents the floating rate as of June 30, 2023, December 31, 2022 and 2021,respectively. During the year ended December 31, 2022, the Credit Facility transitioned from LIBOR to SOFR during the regular spring redetermination. We did not experience a material impact from the transition.
​
Refer to Note 21 in the Notes to the Consolidated Financial Statements and Note 11 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding the ABS Notes, Term Loan I and Credit Facility. The table below represents the impact of a 100 basis point adjustment in the borrowing 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 (In thousands)
​ ​
June 30, 2023
​ ​
December 31, 2022
​ ​
December 31, 2021
​
+100 Basis Points
​ ​ ​ $ 2,650 ​ ​ ​ ​ $ 560 ​ ​ ​ ​ $ 5,706 ​ ​
-100 Basis Points
​ ​ ​ $ (2,650) ​ ​ ​ ​ $ (560) ​ ​ ​ ​ $ (5,706) ​ ​
During 2022, we entered into four ABS financing arrangements with fixed interest rates thereby decreasing our exposure to rising short-term interest rates. We strive to maintain a prudent balance of floating and fixed-rate borrowing exposure, particularly during uncertain market conditions. As part of our risk mitigation strategy from time to time we enter into swap arrangements to increase or decrease exposure to floating or fixed- interest rates to account for changes in the composition of borrowings in our portfolio. As a result, the total principal hedged through the use of derivative financial instruments varies from period to period. The fair value of our interest rate swaps represents an asset of $0.4 million as of June 30, 2023 and a liability of $3 million and $0.1 million as of December 31, 2022 and 2021, respectively Refer to Note 13 in the Notes to the Consolidated Financial Statements and Note 7 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding derivative financial instruments.
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, 2023 and for the years ended December 31, 2022, 2021 and 2020, our commodity revenue was $456 million, $1,873 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% in months 25 to 36, of our anticipated production volumes. Refer to Note 13 in the Notes to the Consolidated Financial Statements and Note 7 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding derivative financial instruments.
By removing price volatility from a significant portion of our expected production through 2032, it has 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
 
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prior to extending credit and generally do not require collateral in support of their trade receivables. We had no customers that comprised over 10% of our total trade receivables from customers as of June 30, 2023 and December 31, 2022, and one customer that comprised 13% of our total trade receivables from customers as of December 31, 2021. As of June 30, 2023, December 31, 2022 and December 31, 2021, our trade receivables from customers were $172 million, $278 million and $268 million, respectively.
We are also exposed to credit risk from joint interest owners, which are individuals and entities that own a working interest in the properties we operate. Joint interest receivables are classified in trade receivables, net in the Consolidated Statement of Financial Position. We have the ability to withhold future revenue payments to recover any non-payment of joint interest receivables. As of June 30, 2023, December 31, 2022 and December 31, 2021, our joint interest receivables were $23 million, $19 million and $15 million, respectively.
The majority of trade receivables are current and we believe these receivables are collectible. Refer to Note 3 in the Notes to the Consolidated Financial Statements found elsewhere in this registration statement for additional information.
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 forecasts 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 does not establish a quantitative return on capital criteria, but rather promote year-over-year Adjusted EBITDA growth. We seek to maintain a leverage target at or below 2.5x after giving effect to acquisitions and any related financing arrangements.
Collateral Risk
We have pledged 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 the Credit Facility) as of June 30, 2023 to fulfil the collateral requirements for borrowings under the ABS Notes and Term Loan I. Our remaining natural gas and oil properties collateralize the Credit Facility. The fair value of the borrowings collateral is based on a third-party engineering reserve calculation using estimated cash flows discounted at 10% and a commodities futures price schedule. Refer to Notes 5 and 21 in the Notes to the Consolidated Financial Statements and Notes 4 and 11 in the Notes to the Interim Condensed Consolidated Financial Statements found elsewhere in this registration statement for additional information regarding acquisitions and borrowings, respectively.
Internal Control Over Financial Reporting
During the preparation of our December 31, 2021 consolidated financial statements, we identified a material weakness pertaining 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. During 2022, we implemented a remediation plan, primarily consisting of adding control activities to re-validate the completeness and accuracy of the data provided to specialists throughout the business combination business cycle for each acquisition. While we believe our remediation efforts were successful, we are also not currently required to evaluate our internal control over financial reporting in a manner that meets the rules and regulations of the SEC given our foreign private issuer status as a UK public company. As a result, we have not engaged our external auditors to perform an audit over our internal control over financial reporting. Upon completion of this listing, we will be subject to Section 404 of the Sarbanes-Oxley Act of
 
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2002 which requires that we include a report of management on our internal control over financial reporting in our second annual report on Form 20-F. In addition, our independent registered public accounting firm must attest to and report on the effectiveness of our internal control over financial reporting in our second annual report on Form 20-F. No other material weakness in financial reporting has been identified in 2020, 2021, 2022 or during the first six months of 2023.
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 Relating to Our Ordinary Shares — Failure to comply with requirements to design, implement and maintain effective internal control over financial reporting could have a material adverse effect on our business.”
C.   Research and Development, Patents and Licenses, etc.
Not Applicable.
D.   Trend Information
Other than as disclosed elsewhere in this registration statement, we are not aware of any trends, uncertainties, demands, commitments or events since December 31, 2022 that are reasonably likely to have a material adverse effect on our revenues, income, profitability, liquidity or capital resources, or that would cause the disclosed financial information to be not necessarily indicative of future operating results or financial conditions. For a discussion of trend information, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — Key factors Affecting Our Performance.”
E.   Critical Accounting Estimates
Refer to Note 4 (Significant Accounting Judgments and Estimates) in the Notes to the Consolidated Financial Statements as of December 31, 2022 found elsewhere in this registration statement for information regarding our significant judgments and estimates.
Item 6.   Directors, Senior Management and Employees
A.   Directors and Senior Management
The following table presents information about our current executive directors and board members, including their ages as of October 31, 2023:
Name
​ ​
Age
​ ​
Position
​
Robert Russell (“Rusty”) Hutson, Jr.
​ ​ 54 ​ ​ Co-Founder, Chief Executive Officer and Director ​
Bradley G. Gray(1) ​ ​ 55 ​ ​ President and Chief Financial Officer ​
Benjamin Sullivan ​ ​ 44 ​ ​ Senior Executive Vice President, Chief Legal & Risk Officer, and Corporate Secretary ​
David E. Johnson(2)(3)(4) ​ ​ 63 ​ ​ Independent Chairman of the Board ​
Martin K. Thomas(3)(5) ​ ​ 59 ​ ​ Vice Chairman of the Board ​
Kathryn Z. Klaber(3)(4)(5) ​ ​ 58 ​ ​ Independent Director ​
Sylvia J. Kerrigan(2)(3) ​ ​ 58 ​ ​ Senior Independent Director ​
Sandra M. Stash(2)(4)(5) ​ ​ 64 ​ ​ Independent Director ​
David J. Turner, Jr.(2)(5) ​ ​ 60 ​ ​ Independent Director ​
​
(1)
Mr. Gray was a director for the 12 month period ended December 31, 2022 and until September 15, 2023, but is no longer an executive director as of the date of this registration statement.
​
(2)
Remuneration Committee member
​
 
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(3)
Nomination and Governance Committee member
​
(4)
Sustainability and Safety Committee member
​
(5)
Audit and Risk 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.
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 President and Chief Financial Officer since September 2023, and prior to that served as Executive Vice President, Chief Operating Officer since October 2016. 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).
Benjamin Sullivan has served as our Senior Executive Vice President, Chief Legal & Risk Officer, and Corporate Secretary since September 2023, and prior to that served as Executive Vice President, General Counsel and Corporate Secretary since 2019. Prior to joining us, Mr. Sullivan worked with Greylock Energy, LLC (an ArcLight Capital Partners portfolio company) and its predecessor, Energy Corporation of America, from 2012 to 2017, most recently as Executive Vice President, General Counsel and Corporate Secretary from 2017 to 2019. Prior to that, Mr. Sullivan served as counsel for EQT Corporation from 2006 to 2012. He is a member of the leadership and board of directors of several commerce, legal and industry groups, and has considerable experience in corporate governance and reporting/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 several states, including Pennsylvania and West Virginia.
David E. Johnson has served on our board of directors since February 2017 and as our Independent Chairman of the Board since April 2019. He has worked at a number of leading investment firms, as both an investment analyst and a manager, and more recently in equity sales and investment management. Mr. Johnson currently serves on the board of Chelverton Equity Partners, an AIM-listed holding company, where he serves as a member of the Remuneration, Audit and Nomination committees. Previously, Mr. Johnson was a consultant at Chelverton Asset Management from August 2016 to February 2019. Prior to that, he worked as a fund manager for the investment department a large insurance company and then as Head of Sales and Head of Equities at a London investment bank. Mr. Johnson earned a Bachelor of Arts in Economics from the University of Reading.
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 UK.
Kathryn Z. Klaber has served on our board of directors since January 2023. Since 2014, Ms. Klaber has served as the Managing Director of The Klaber Group, which provides strategic consulting services to businesses and organizations with a focus on energy development in the United States and abroad. Prior to founding The Klaber Group, Ms. Klaber launched the Marcellus Shale Coalition, serving as its first CEO from 2009 to 2013. Previously in her career, Ms. Klaber also served as the Executive Vice President for Competitiveness at the Allegheny Conference on Community Development, Executive Director of the
 
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Pennsylvania Economy League, and consultant at Environmental Resources Management, where she gained significant experience in EHS strategy and compliance. Ms. Klaber received her B.A. in Environmental Science from Bucknell University and her MBA from Carnegie Mellon University.
Sylvia J. Kerrigan has served on our board of directors since October 2021. Currently, she is the Chief Legal Officer at Occidental Petroleum Corporation (NYSE: OXY). Prior to joining Occidental, Ms. Kerrigan served as the Executive Director of the Kay Bailey Hutchinson Center for Energy, Law and Business at the University of Texas, where she remains a member of the Executive Council. In Ms. Kerrigan’s more than 20 years with Marathon Oil Corporation, she served in a number of roles overseeing public policy, legal and compliance, corporate positioning and external communications before retiring in 2017 after eight years as the Executive Vice President, General Counsel and Corporate Secretary. Ms. Kerrigan has also served as a director for Hornbeck Offshore Services, Inc. since August 2022 and Vice-Chair of the Board of Trustees for Southwestern University since March 2014. Ms. Kerrigan holds a Directorship Certification through the National Association of Corporate Directors. Ms. Kerrigan earned a Bachelor of Arts from Southwestern University and a Doctor of Jurisprudence from the University of Texas at Austin School of Law.
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 Corporate Directors and currently serves on the boards of Chaarat Gold Holdings Limited (AIM: CGH), Trans Mountain Company, Warriors and Quiet Waters, 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.
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. Before beginning his banking career, Mr. Turner was a certified public accountant and an Audit Partner with Arthur Andersen and KPMG specializing in financial services clients. He earned a Bachelor of Science in Accounting from the University of Alabama.
Family Relationships
There are no family relationships among any of our executive officers or directors.
Appointment Rights
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 our Articles of Association.
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.
 
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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.
B.   Compensation
Compensation of Executive Directors and Key Management Compensation
For the year ended December 31, 2022, the aggregate compensation paid to the members of our board of directors and our executive officers for services in all capacities was approximately $10 million. This amount includes the following compensation paid to our executive directors for the year ended December 31, 2022:
Name
​ ​
Base
Salary
​ ​
Annual
Bonus
​ ​
Non-Equity
Incentive Plan
Compensation
​ ​
All Other
Compensation
​ ​
Total
​
​ ​ ​
(Amounts rounded to the nearest thousand)
​
Robert Russell (“Rusty”) Hutson, Jr.
​ ​ ​ $ 719,932 ​ ​ ​ ​ $ 1,072,488 ​ ​ ​ ​ $ 49,276 ​ ​ ​ ​ $ 4,029,582 ​ ​ ​ ​ $ 5,871,278 ​ ​
Bradley G. Gray(1)
​ ​ ​ $ 437,240 ​ ​ ​ ​ $ 558,043 ​ ​ ​ ​ $ 47,500 ​ ​ ​ ​ $ 2,378,157 ​ ​ ​ ​ $ 3,420,940 ​ ​
​
(1)
Mr. Gray was a director for the 12 month period ended December 31, 2022 and until September 15, 2023, but is no longer an executive director as of the date of this registration statement.
​
Pension, Retirement or Similar Benefits
Our executive officers are entitled to matching contributions from us of up to $23,100 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.
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 £1,055,000 per annum.
The following table sets forth the compensation paid during 2022 to the current non-executive directors, all of which was in the form of annual fees:
Name
​ ​
Compensation
​
​ ​ ​
(amounts in $)
​
David E. Johnson
​ ​ ​ ​ 199,698 ​ ​
Martin K. Thomas
​ ​ ​ ​ 145,212 ​ ​
David J. Turner, Jr.
​ ​ ​ ​ 155,842 ​ ​
Sandra M. Stash
​ ​ ​ ​ 144,554 ​ ​
Melanie A. Little
​ ​ ​ ​ 145,108 ​ ​
Sylvia J. Kerrigan
​ ​ ​ ​ 120,275 ​ ​
 
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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.
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 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.
 
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The following table summarizes the number of outstanding shares and options granted to executive directors and non-executive directors, as of June 30, 2023:
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.
​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,286,666 ​ ​ ​
£0.84
​ ​ ​ ​ 04/14/2018 ​ ​ ​
04/14/2028
​ ​
2017 Equity Incentive Plan
​
​ ​ ​ — ​ ​ ​ ​ ​ 932,000 ​ ​ ​
£1.20
​ ​ ​ ​ 05/09/2019 ​ ​ ​
05/09/2029
​ ​
2017 Equity Incentive Plan
​
​ ​ ​ 1,113,874 ​ ​ ​ ​ ​ — ​ ​ ​
n/a
​ ​ ​ ​ 03/15/2021 ​ ​ ​
n/a
​ ​
2017 Equity Incentive Plan
​
​ ​ ​ 1,691,660 ​ ​ ​ ​ ​ — ​ ​ ​
n/a
​ ​ ​ ​ 03/15/2022 ​ ​ ​
n/a
​ ​
2017 Equity Incentive Plan
​
​ ​ ​ 2,113,938 ​ ​ ​ ​ ​ — ​ ​ ​
n/a
​ ​ ​ ​ 03/21/2023 ​ ​ ​
n/a
​ ​
2017 Equity Incentive Plan
​
Bradley G. Gray(1)
​ ​ ​ ​ — ​ ​ ​ ​ ​ 589,721 ​ ​ ​
£0.84
​ ​ ​ ​ 04/14/2018 ​ ​ ​
04/14/2028
​ ​
2017 Equity Incentive Plan
​
​ ​ ​ — ​ ​ ​ ​ ​ 427,166 ​ ​ ​
£1.20
​ ​ ​ ​ 05/09/2019 ​ ​ ​
05/09/2029
​ ​
2017 Equity Incentive Plan
​
​ ​ ​ 684,825 ​ ​ ​ ​ ​ — ​ ​ ​
n/a
​ ​ ​ ​ 03/15/2021 ​ ​ ​
n/a
​ ​
2017 Equity Incentive Plan
​
​ ​ ​ 866,715 ​ ​ ​ ​ ​ — ​ ​ ​
n/a
​ ​ ​ ​ 03/15/2022 ​ ​ ​
n/a
​ ​
2017 Equity Incentive Plan
​
​ ​ ​ 1,068,713 ​ ​ ​ ​ ​ — ​ ​ ​
n/a
​ ​ ​ ​ 03/21/2023 ​ ​ ​
n/a
​ ​
2017 Equity Incentive Plan
​
Non-Executive Directors ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
David E. Johnson
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Martin K. Thomas
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
David J. Turner, Jr
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Sandra M. Stash
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Kathryn Z. Klaber
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Sylvia J. Kerrigan
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
​
(1)
Mr. Gray was a director for the 12 month period ended December 31, 2022, but is no longer an executive director as of the date of this registration statement.
​
2023 Employee Stock Purchase Plan
We have adopted the Diversified Energy Company PLC Employee Stock Purchase Plan, as may be amended from time to time (the “ESPP”), which is intended to constitute an “employee stock purchase plan” within the meaning of Section 423(b) of the U.S. Internal Revenue Code of 1986, as amended (the “Code”). The material terms of the ESPP are summarized below.
Shares Available.   The maximum number of our ordinary shares that may be issued under the ESPP shall not exceed 6,000,000 ordinary shares.
Administration.   Our board of directors or the remuneration committee will have authority to adopt such rules, regulations, guidelines and forms as they deem necessary for the proper administration of the ESPP, to interpret the provisions and supervise the administration of the ESPP, and to take all necessary or advisable actions in connection with administration of the ESPP.
Eligibility.   The plan administrator may designate certain of our subsidiaries and/or parent corporations, whether now or subsequently established, as participating “related corporations” in any given offering under the ESPP. Employees of our company and our designated related corporations are eligible to participate in the ESPP if they meet the eligibility requirements under the ESPP and applicable offering. Members of our board of directors, including executive directors, are not eligible to participate in the ESPP.
Subject to certain conditions and exceptions, the plan administrator may provide that each person, who, during an offering, first becomes an eligible employee, will receive a purchase right under that offering on a date specified in the offering. Employees who choose not to participate in an offering may enroll in any subsequent offering period, provided the eligibility and other applicable requirements are met.
 
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In no event may an employee be granted rights to purchase stock under the ESPP if such employee, immediately after the grant, would own (directly or through attribution) stock possessing 5% or more of the total combined voting power or value of all classes of all shares of the Company or of any related corporation.
The plan administrator may establish sub-plans and initiate separate offerings through such sub-plans for the purpose of (i) facilitating participation in the ESPP by non-U.S. employees in compliance with foreign laws and regulations, without affecting the qualification of the remainder of the ESPP under Section 423 of the Code, or (ii) qualifying the ESPP for preferred tax treatment under U.S. or foreign tax laws. Alternatively, and in order to comply with the laws of a domestic or foreign jurisdiction, the plan administrator may, in its discretion, establish less favorable offering terms and conditions for citizens or residents of non-U.S. jurisdictions than for the employees residing in the United States.
Participation in an Offering.   Eligible employees can become participants in the ESPP by enrolling and authorizing payroll deductions by the deadline established by the plan administrator for the applicable offering. Ordinary shares will be offered under the ESPP during the periods of time established by the plan administrator for each offering (i.e., offering periods). The length of offering periods under the ESPP will be determined by the plan administrator and may not exceed 27 months. Employee payroll deductions will be used to purchase shares on each purchase date during an offering period. The number of purchase periods within, and purchase dates during, each offering period will be established by the plan administrator. Offering periods under the ESPP will commence when determined by the plan administrator. The plan administrator may, in its discretion and subject to the ESPP requirements, establish new or different terms for future offering periods.
The ESPP permits participants to purchase our ordinary shares through payroll deductions of up to 15% of their compensation (as defined by the plan administrator in each offering), which may be determined as a percentage of compensation or a maximum dollar amount. Participants may reduce or increase their contributions during an offering period, so long as it is permitted in the offering, company policies and under applicable law. If required under applicable law or specifically provided in the offering, in addition to or instead of making contributions by payroll deductions, a participant may make contributions through the payment by cash, check or wire transfer prior to a purchase date.
In connection with each offering, the plan administrator may establish (i) a maximum number of shares that may be purchased by any participant on any purchase date during such offering, (ii) a maximum aggregate number of shares that may be purchased by all participants pursuant to such offering, (iii) a maximum aggregate number of shares that may be purchased by all participants on any purchase date under the offering, and/or (iv) a maximum and/or minimum contribution amount. In addition, no eligible employee is permitted to accrue purchase rights under the ESPP if such rights, together with any other rights granted under all employee stock purchase plans of the Company and any related corporations, permit such eligible employee’s purchase rights to accrue at a rate which, when aggregated, exceeds $25,000 worth of shares during any calendar year during which such rights are outstanding (based on the fair market value of such shares determined at the time the purchase rights are granted).
On each offering date, each participant will be granted a purchase right to purchase our ordinary shares. On each purchase date, each participant’s accumulated contributions will be applied towards the purchase of ordinary shares at the purchase price specified in the offering document. The purchase price will be established by the plan administrator, but will not be less than 85% of the lower of the fair market value of our ordinary shares on the offering date or on the applicable purchase date.
Subject to compliance with a withdrawal deadline, if any, participants may voluntarily end their participation in the ESPP by delivering to the Company a withdrawal form, and will be paid their accumulated but unused contributions that have not yet been used to purchase our ordinary shares. Upon such withdrawal, the participant’s purchase right in the offering will immediately terminate. Participation ends automatically if a participant is no longer an employee for any reason or for no reason (subject to any post-employment participation period required by law) or otherwise becomes ineligible to participate in the ESPP.
Transferability.   A participant may not transfer rights granted under the ESPP other than by will, the laws of descent and distribution or, if permitted by the Company, by a beneficiary designation.
 
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Certain Transactions.   In the event of capitalization adjustments (i.e., certain transactions or events affecting our ordinary shares, without the receipt of consideration by the Company, such as merger, consolidation, reorganization, recapitalization, reincorporation, share dividend, dividend in property other than cash, large nonrecurring cash dividend, share split, liquidating dividend, combination of shares, exchange of shares, change in corporate structure or other similar equity restructuring transactions), the plan administrator will make equitable adjustments to the ESPP and outstanding rights. In addition, in the event of a corporate transaction (as defined in the ESPP), (i) any surviving company or acquiring company (or its parent company) may assume or continue outstanding purchase rights or may substitute similar rights (including a right to acquire the same consideration paid to the shareholders in the corporate transaction) for outstanding purchase rights, or (ii) if any surviving or acquiring company (or its parent company) does not assume or continue such purchase rights or does not substitute similar rights for such purchase rights, then the participants’ accumulated contributions will be used to purchase ordinary shares within 10 business days prior to the corporate transaction under the outstanding purchase rights, and the purchase rights and the ESPP will terminate immediately after such purchase.
Plan Amendment; Termination.   The plan administrator may amend, suspend or terminate the ESPP at any time. However, shareholder approval will be required for any amendment of the ESPP for which shareholder approval is required by applicable law.
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.
C.   Board Practices
Composition of our Board of Directors
Our board of directors is composed of seven members. As a foreign private issuer, under the listing requirements and rules of the NYSE, we are not required to have independent directors on our board 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 has determined that six of our seven 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 NYSE.
Duration of Board Term
Our executive director’s service agreement is of indefinite duration, subject to termination by the Company or the individual on 6 months’ notice. The service agreements of our current executive director complies with that policy. Each non-executive director serves on our board of directors for an initial period of 12 months, subject to re-election at each annual general meeting of the Company and are terminable on three months’ notice given by either party.
Executive Director Employment Agreements
We entered into written service agreements with each of our executive directors who were on the board for fiscal year 2022. 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. The Executive Director Remuneration Policy entitles Mr. Hutson to receive a base salary of $749,840 for 2023 and an opportunity
 
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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.
Annual bonus plan levels and the appropriateness of measures are reviewed annually at the commencement of each financial year to ensure they continue to support the Company’s strategy. The performance measures applied may be financial or non-financial; quantitative and qualitative; and corporate, divisional or individual and with such weightings as the Remuneration Committee considers appropriate. The metrics and weightings applicable in 2023 are as follows: 50% Adjusted EBITDA per Share, 20% Cash Cost per Mcfe and 30% ESG/EHS. 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 six 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 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
Mr. Gray was a director for the 12 month period ended December 31, 2022, but is no longer an executive director as of the date of this registration statement. We entered into a service agreement with Mr. Gray on January 30, 2017. The Executive Director Remuneration Policy entitles Mr. Gray to receive a base salary of $455,188 for 2023 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.
Annual bonus plan levels and the appropriateness of measures are reviewed annually at the commencement of each financial year to ensure they continue to support the Company’s strategy. The performance measures applied may be financial or non-financial; quantitative and qualitative; and corporate, divisional or individual and with such weightings as the Remuneration Committee considers appropriate. The metrics and weightings applicable in 2023 are as follows: 50% Adjusted EBITDA per Share, 20% Cash Cost per Mcfe and 30% ESG/EHS. 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 six 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 six 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.
Corporate Governance Practices and Foreign Private Issuer Status
Companies listed on the NYSE must comply with the corporate governance standards provided under Section 303A of the NYSE Listed Company Manual. As a “foreign private issuer,” as defined by the SEC,
 
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we will be permitted to follow home country corporate governance practices, instead of certain corporate governance practices required by the NYSE for U.S. domestic issuers, except that we are required to comply with Sections 303A.06, 303A.11 and 303A.12(b) and (c) of the Listed Company Manual. Under Section 303A.06, we must have an audit committee that meets the independence requirements of Rule 10A-3 under the Exchange Act. Under Section 303A.06, we must disclose any significant ways in which their corporate governance practices differ from those followed by domestic companies under NYSE listing standards. Finally, under Section 303A.12(b) and (c), we must promptly notify the NYSE in writing after becoming aware of any non-compliance with any applicable provisions of this Section 303A and must annually make a written affirmation to the NYSE. Further, an LSE listed company must disclose in its annual financial report a statement of how the listed company has applied the principles set out in the UK Corporate Governance Code, in a manner that would enable shareholders to evaluate how the principles have been applied, and a statement as to whether the listed company has (a) complied throughout the accounting period with all relevant provisions set out in the UK Corporate Governance Code; or (b) not complied throughout the accounting period with all relevant provisions set out in the UK Corporate Governance Code and if so, setting out: (i) those provisions, if any it has not complied with; (ii) in the case of provisions whose requirements are of a continuing nature, the period within which, if any, it did not comply with some or all of those provisions; and (iii) the company’s reasons for non-compliance.
The table below briefly describes the significant differences between our UK corporate governance practices and the NYSE corporate governance rules.
Section
​ ​
NYSE Corporate Governance Rules
​ ​
UK Corporate Governance Practices
​
303A.01 ​ ​ 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. ​
303A.02 ​ ​ 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;
​
 ​
 
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Section
​ ​
NYSE Corporate Governance Rules
​ ​
UK Corporate Governance Practices
​
​ ​ ​ ​ ​ ​
•
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 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.
​
303A.03 ​ ​ 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. 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.
​
303A.04 ​ ​ 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. ​
303A.05 ​ ​ 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 ​
 
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Section
​ ​
NYSE Corporate Governance Rules
​ ​
UK Corporate Governance Practices
​
​ ​ ​ ​ ​ ​ committee. Before appointment as chair of the remuneration committee, the appointee should have served on a remuneration committee for at least 12 months. ​
303A.06 ​ ​
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 Section 303A.06, where we must have an audit committee that satisfies the requirements of Exchange Act Rule 10A-3.
​ ​ 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. ​
303A.08 ​ ​ Shareholders must be given the opportunity to vote on all equity-compensation plans and material revisions thereto, with limited exemptions set forth in the NYSE 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. ​
303A.09 ​ ​ 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. ​
303A.10 ​ ​
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
​ ​ 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 choose to adopt one. ​
 
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Section
​ ​
NYSE Corporate Governance Rules
​ ​
UK Corporate Governance Practices
​
​ ​ ​ NYSE corporate governance listing standards. ​ ​ ​ ​
303A.12 ​ ​
(a)
Each listed company CEO must certify to the NYSE each year that he or she is not aware of any violation by the company of NYSE corporate governance listing standards.
​
(b)
Each listed company CEO must promptly notify the NYSE in writing after any executive officer of the listed company becomes aware of any non-compliance with any applicable provisions of this Section 303A.
​
(c)
Each listed company must submit an executed Written Affirmation annually to the NYSE. In addition, each listed company must submit an interim Written Affirmation as and when required by the interim Written Affirmation form specified by the NYSE.
​
As a foreign private issuer, we are required to comply with Section 303A.12.
​ ​ ​ ​
Section 312.03 of the NYSE Rules also requires that a listed company obtain, in specified circumstances, (1) shareholder approval to adopt or materially revise equity compensation plans, as well as (2) shareholder approval prior to an issuance (a) of more than 1% of its ordinary shares (including derivative securities thereof) in either number or voting power to related parties, (b) of more than 20% of its outstanding ordinary shares (including derivative securities thereof) in either number or voting power or (c) that would result in a change of control. We intend to follow home country law in determining whether shareholder approval is required.
Section 302 of the NYSE Rules also requires that a listed company hold an annual shareholders’ meeting for holders of securities during each fiscal year. We may follow home country law in determining whether and when such shareholders’ meetings are required.
We may in the future decide to use other foreign private issuer exemptions with respect to some or all of the other requirements under the NYSE Rules. Following our home country governance practices may provide less protection than is accorded to investors under the NYSE listing requirements applicable to domestic issuers.
We intend to take all actions necessary for us to maintain compliance as a foreign private issuer under the applicable corporate governance requirements of the Sarbanes-Oxley Act of 2002, the rules adopted by the SEC and NYSE listing standards.
Because we are a foreign private issuer, our directors and senior management are not subject to short-swing profit and insider trading reporting obligations under Section 16 of the Exchange Act. They will, however, be subject to the obligations to report changes in share ownership under Section 13 of the Exchange Act and related SEC rules.
 
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Committees of our Board of Directors
Our board of directors has four standing committees: an Audit and Risk Committee, a Remuneration Committee, a Nomination and Governance 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 NYSE corporate governance rules, effective upon the effectiveness of the registration statement of which this registration statement 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 registration statement, and you should not consider information on our website to be part of this registration statement.
Audit and Risk Committee
Under NYSE 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 Kathryn Z Klaber, 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 and the NYSE 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 NYSE 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 NYSE corporate governance rules.
Upon completion of this listing, 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;
​
•
overseeing and advising the board on cybersecurity matters;
​
 
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•
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, Sandra M. Stash, David J. Turner, and Sylvia J. Kerrigan. Ms. Kerrigan serves as Chair of the Remuneration Committee. Under SEC and NYSE 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 registration statement, 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 NYSE corporate governance rules.
Upon completion of this listing, the Remuneration Committee will be responsible for, among other things:
•
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 and Governance Committee
Our Nomination and Governance Committee consists of Kathryn Z. Klaber, Sylvia J. Kerrigan, and Martin K. Thomas. Ms. Klaber serves as the Chair of the Nomination and Governance Committee.
The Nomination and Governance Committee charter will set forth the responsibilities of the Nomination and Governance Committee consistent with UK law, the SEC rules and the NYSE corporate governance rules.
Upon completion of this listing, the Nomination and Governance 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;
​
•
monitoring the Company’s governance structure and trends and compliance with governance best practice;
​
•
succession planning for directors;
​
 
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•
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 and Governance 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, Kathryn Z. Klaber 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 and ESG 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 and EHS audits and the action plans proposed pursuant to those findings.
​
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 listing, 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 this registration statement, 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 registration statement and is not incorporated by reference herein.
D.   Employees
As of December 31, 2022, we had 1,582 full-time employees.
The table below sets out the number of employees by geography:
Geography
​ ​
As of
December 31, 2022
​ ​
As of
December 31, 2021
​ ​
As of
December 31, 2020
​
EMEA
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
United States
​ ​ ​ ​ 1,582 ​ ​ ​ ​ ​ 1,426 ​ ​ ​ ​ ​ 1,107 ​ ​
Total
​ ​ ​ ​ 1,582 ​ ​ ​ ​ ​ 1,426 ​ ​ ​ ​ ​ 1,107 ​ ​
 
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The table below sets out the number of employees by category of activity:
Department
​ ​
As of
December 31, 2022
​ ​
As of
December 31, 2021
​ ​
As of
December 31, 2020
​
Production
​ ​ ​ ​ 1,220 ​ ​ ​ ​ ​ 1,143 ​ ​ ​ ​ ​ 924 ​ ​
Production Support
​ ​ ​ ​ 362 ​ ​ ​ ​ ​ 283 ​ ​ ​ ​ ​ 183 ​ ​
Total ​ ​ ​ ​ 1,582 ​ ​ ​ ​ ​ 1,426 ​ ​ ​ ​ ​ 1,107 ​ ​
In line with industry standards in the country of employment, our employees maintain a range of relationships with union groups.
We have not previously experienced labor-related work stoppages or strikes and believe that our relations with our employees are satisfactory.
E.   Share Ownership
For information regarding the share ownership of directors and officers, see “Item 7. Major Shareholders and Related Party Transactions — A. Major Shareholders.” For information as to our equity incentive plans, see “Item 6. Directors, Senior Management and Employees — B. Compensation — Incentive Programs.”
F.   Clawback Policy
Not applicable.
Item 7.   Major Shareholders and Related Party Transactions
A.   Major Shareholders
The following table sets forth information relating to the beneficial ownership of our ordinary shares as of October 31, 2023 by:
•
each person, or group of affiliated persons, known by us to beneficially own 3% 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 October 31, 2023 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.
Unless otherwise indicated below, the address for each beneficial owner listed is c/o Diversified Energy Company plc, 1600 Corporate Drive, Birmingham, Alabama 35242.
For further information regarding material transactions between us and principal shareholders, see “Item 7. Major Shareholders and Related Party Transactions — B. Related Party Transactions.”
 
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Name of beneficial owner
​ ​
Number of
ordinary shares
beneficially owned
​ ​
Percentage of
ordinary shares
beneficially owned
​
3% or Greater Shareholders ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
M&G Investment Management Ltd
​ ​ ​ ​ 61,964,389 ​ ​ ​ ​ ​ 6.41% ​ ​
BlackRock
​ ​ ​ ​ 53,005,207 ​ ​ ​ ​ ​ 5.48% ​ ​
Columbia Management Investment Advisors, LLC
​ ​ ​ ​ 47,961,224 ​ ​ ​ ​ ​ 4.96% ​ ​
Vanguard Group Inc.
​ ​ ​ ​ 45,696,311 ​ ​ ​ ​ ​ 4.73% ​ ​
Abrdn Investment Management Ltd
​ ​ ​ ​ 45,349,234 ​ ​ ​ ​ ​ 4.69% ​ ​
JO Hambro Capital Management Ltd
​ ​ ​ ​ 43,429,215 ​ ​ ​ ​ ​ 4.49% ​ ​
GLG Partners LP
​ ​ ​ ​ 43,115,229 ​ ​ ​ ​ ​ 4.46% ​ ​
Executive Officers and Directors ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Robert Russell (“Rusty”) Hutson, Jr
​ ​ ​ ​ 24,152,890 ​ ​ ​ ​ ​ 2.49% ​ ​
Bradley G. Gray
​ ​ ​ ​ 2,938,935 ​ ​ ​ ​ ​ * ​ ​
Benjamin Sullivan
​ ​ ​ ​ 616,280 ​ ​ ​ ​ ​ * ​ ​
Martin K. Thomas
​ ​ ​ ​ 2,245,000 ​ ​ ​ ​ ​ * ​ ​
David Johnson
​ ​ ​ ​ 475,000 ​ ​ ​ ​ ​ * ​ ​
David J. Turner, Jr.
​ ​ ​ ​ 538,475 ​ ​ ​ ​ ​ * ​ ​
Kathryn Z. Klaber
​ ​ ​ ​ 21,000 ​ ​ ​ ​ ​ * ​ ​
Sylvia J. Kerrigan
​ ​ ​ ​ 26,827 ​ ​ ​ ​ ​ * ​ ​
Sandra M. Stash
​ ​ ​ ​ 44,681 ​ ​ ​ ​ ​ * ​ ​
All executive officers and directors as a group (9 persons)
​ ​ ​ ​ 31,059,088 ​ ​ ​ ​ ​ 3.20% ​ ​
​
*
Indicates ownership of less than 1%.
​
According to our registrar, as of June 30, 2023, there were 57 registered holders of our ordinary shares with addresses in the United States representing approximately 22.77% of our outstanding ordinary shares as of that date. Because some of the Company’s ordinary shares are held through brokers or other nominees, the number of record holders of the Company’s ordinary shares with addresses in the United States may be fewer than the number of beneficial owners of ordinary shares in the United States.
To our knowledge, other than as provided in the table above, there has been no significant change in the percentage ownership held by any major shareholder since January 1, 2020. The major shareholders listed above do not have voting rights with respect to their ordinary shares that are different from the voting rights of other holders of our ordinary shares.
We are not aware of any arrangement whereby we are directly or indirectly owned or controlled by another corporation, by any foreign government or by any other natural or legal person severally or jointly, nor are we aware of any arrangement that may, at a subsequent date, result in a change of control of the Company.
B.   Related Party Transactions
The following is a description of the material and/or non-ordinary course transactions we have entered into since January 1, 2020 with any of our directors or executive officers and the holders of more than 10% of our ordinary shares. For a description of our agreements with our executive officers and certain of our directors, see “Item 6. Directors, Senior Management and Employees — B.Compensation”
Martin K. Thomas, a member of our board of directors, currently serves as a consultant at Wedlake Bell LLP (“Wedlake Bell”), the former UK legal advisor to the Company, where he was formerly a partner. During the years ended December 31, 2020, 2021 and 2022, the Company paid fees in the amounts of $41,000, $0 and $0, respectively, to Wedlake Bell.
 
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Transactions with Our Executive Officers and Directors
For a description of our other agreements with our directors and executive officers, please see “Item 6.B “Compensation”
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 “Item 6. Directors, Senior Management and Employees — B. Compensation” for a description of these indemnification agreements.
Related Party Transaction Policy
Prior to the completion of this listing, 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 material and/or non-ordinary course related person transactions.
C.   Interests of Experts and Counsel
Not applicable.
Item 8.   Financial Information
A.   Consolidated Statements and Other Financial Information
Consolidated Financial Statements
See “Item 18. Financial Statements” for a list of all financial statements filed as part of this registration statement.
Share Consolidation
In order to qualify for a listing on the NYSE, a company’s shares must have a minimum value of US$4.00 at the time of listing. The closing price of our existing shares on the LSE as of November 14, 2023 was £0.7075 (equivalent to US$0.88434 calculated on the basis of the pound sterling to US dollar spot rate of exchange rate (the closing midpoint) on the thereof). Accordingly, the board of directors proposes to implement a share consolidation of the Company’s ordinary share capital pursuant to which every 20 previously existing shares in issue at the consolidation record time will be consolidated into one new share, the purpose of which is to seek to ensure that the NYSE minimum share price requirement will be met on the effective date of the US Listing.
Share Repurchase Program
In June 2023, we commenced a share repurchase program for an aggregate purchase price up to no more than £97.4 million or 97,410,000 of ordinary shares. In addition, 200,000 ordinary shares purchased as part of the share repurchase program at an average price of $1.05 per ordinary share were concurrently canceled. These shares are included in the total number of share capital outstanding as of June 30, 2023.
All ordinary shares repurchased under share repurchase programs were cancelled resulting in a transfer of the aggregate nominal value to a capital redemption reserve. The total cost of the purchases made under the share repurchase program during the period, including directly attributable transaction costs, was $0.2 million. Total purchases under the share repurchase program will be made out of distributable profits.
Legal Proceedings
From time to time, we may be involved in legal proceedings in the ordinary course of business. Other than as described in Note 26 included in “Item 18. Financial Statements — Audited Consolidated Financial
 
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Statements”, we are not currently a party to any material litigation proceedings, the outcome of which, if determined adversely to us, individually or in the aggregate, is 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.
Shareholder Dividends
We have historically 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, 2023 and 2022 and during the years ended December 31, 2022, 2021 and 2020, we declared and paid dividends of an aggregate of approximately $84 million, $72 million, $143 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 subject to such restrictions under our Credit Facility, from whom we derive significant 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 25% of the borrowing base thereunder. Please see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
While we cannot provide assurance that we will be able to pay cash dividends on our ordinary shares in future periods, our past practices, which were based on our historical performance and our ability to fund, (but subject to certain restrictions, including those above related to UK Law, and the terms of our Credit Facility), have been to use a portion of our cash flow and/or liquidity to pay dividends on our ordinary shares, subject to our financial condition, cash requirements, future prospects, commodity prices, the performance and dividend yield of our peers, compliance with the financial covenants and restricted payments covenant in our Credit Facility, profits available for distribution and other factors deemed to be relevant at the time and on the continued health of the markets in which we operate. Further, subsequent to our listing on the NYSE, while our Board’s evaluation of our ability or need to pay dividends will primarily remain a question of the foregoing factors, it will also take into account the performance of our ordinary shares, including relative to our peer group. There can be no guarantee that we will continue to pay dividends in the future on our ordinary share.
We have not adopted, and do not currently intend to adopt, a formal written Company shareholder dividends policy prior to the consummation of this listing.
B.   Significant Changes
For information on any significant changes that may have occurred since the date of our annual financial statements, see “Item 5. Operating and Financial Review and Prospects.”
Item 9.   The Listing
A.   Listing Details
Our only issued and outstanding shares are our ordinary shares of £0.01 nominal (par) value each. We have no other outstanding class of equity securities. Our issued and outstanding ordinary shares are fully paid. Our ordinary shares are in certificated and uncertificated form.
The principal trading market for the Company’s ordinary shares is the London Stock Exchange, where the Company’s ordinary shares are traded under the symbol “DEC.”
 
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We are in the process of applying to have our ordinary shares listed on the New York Stock Exchange (“NYSE”) under the symbol “DEC” ​(the “U.S. Listing”). We make no representation that such application will be approved or that our ordinary shares will trade on such market either now or at any time in the future.
Our ordinary shares are currently traded on the London Stock Exchange’s main market for listed securities and such trades are settled through the CREST system in the United Kingdom. Upon completion of the U.S. Listing, our ordinary shares will also be eligible to be traded on NYSE and such trades will be settled through The Depository Trust Company (“DTC”) system in the United States.
On the business day prior to the effective time of our U.S. Listing (the “Initial Depositary Transfer Date”), all of our ordinary shares, other than those that bear a restrictive legend prohibiting such ordinary shares from being freely transferred in the United States whether pursuant to a contractual restriction or U.S. securities laws (such legended ordinary shares, the “Restricted Shares”), held in uncertificated form within the CREST system will be transferred to Cede & Co. (“Cede”) as the nominee operating on behalf of DTC, and deposited with DTC. In order to enable holders of uncertificated ordinary shares to continue to transfer and settle their interests through CREST after the Initial Depositary Transfer Date in the manner in which they did prior to such time in all material respects, such shareholders will receive depositary interests operated by Computershare Investor Services PLC (the “DI Issuer”) through CREST representing ordinary shares (“DIs”) on a one-for-one basis. Accordingly, after the Initial Depositary Transfer Date, holders of uncertificated ordinary shares (other than the Restricted Shares) will instead be able to transfer and settle trades in respect of shares placed on the LSE through the transfer of DIs in CREST.
On the Initial Depositary Transfer Date, all of our ordinary shares (other than the Restricted Shares) held in certificated form will also be transferred to and deposited with DTC. Computershare Trust Company, N.A., as election agent (the “Election Agent”), will hold such shares in custody, and holders of ordinary shares in certificated form will, for 180 calendar days, be given the opportunity, in respect of their underlying entitlement to shares, to elect to either: (i) have the book-entry interests transferred within DTC from the Election Agent to another bank, broker or nominee (selected by the holder) who is a participant in DTC or CREST; or (ii) hold the underlying shares in certificated form (in which case, the relevant book-entry interests held by the Election Agent within DTC shall be cancelled and a corresponding number of shares will be transferred from Cede to the electing certificated shareholder and a share certificate will be issued in respect of those shares). Following expiry of the 180-calendar day period (and in the absence of any election with respect to their shares), such holders will be issued a certificate in respect of their ordinary shares and will be the registered or record holder of such ordinary shares.
At the effective time of our U.S. Listing, all of our Restricted Shares will automatically be transferred to GTU Ops Inc. (as nominee for Computershare Trust Company N.A.), and Computershare Trust Company N.A. (as depositary for the holders of the Restricted Shares) will issue depositary receipts to such holders in respect of their Restricted Shares on a one-for-one basis.For additional details regarding our ordinary shares, see “Item 10. Additional Information — A. Share Capital.”
B.   Plan of Distribution
Not applicable.
C.   Markets
Our ordinary shares are listed on the London Stock Exchange (“LSE”) under the symbol “DEC.” We also intend to apply to list our ordinary shares on the New York Stock Exchange (“NYSE”) under the symbol “DEC.”
D.   Selling Shareholders
Not Applicable.
E.   Dilution
Not applicable.
 
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F.   Expenses of the Issue
Not applicable.
Item 10.   Additional Information
A.   Share Capital
​
Balance as of December 31, 2021
​ ​ ​ ​ 849,654,653 ​ ​
​
Issuance of share capital (settlement of warrants)
​ ​ ​ ​ 513,901 ​ ​
​
Issuance of share capital (equity compensation)
​ ​ ​ ​ 792,575 ​ ​
​
Issuance of EBT shares (equity compensation)
​ ​ ​ ​ 1,760,025 ​ ​
​
Repurchase of shares (EBT)
​ ​ ​ ​ (15,790,396) ​ ​
​
Repurchase of shares (share buyback program)
​ ​ ​ ​ (7,995,376) ​ ​
​
Balance as of December 31, 2022
​ ​ ​ ​ 828,935,382 ​ ​
​
Issuance of share capital (equity placement)
​ ​ ​ ​ 128,444,000 ​ ​
​
Issuance of EBT shares (equity compensation)
​ ​ ​ ​ 5,913,620 ​ ​
​
Repurchase of shares (share buyback program)
​ ​ ​ ​ (200,000) ​ ​
​
Balance as of June 30, 2023
​ ​ ​ ​ 963,093,002 ​ ​
As of June 30, 2023, our issued share capital amounted to £9,630,930, represented by 963,093,002 ordinary shares with a nominal value of £0.01 per share. All issued ordinary shares are fully paid.
As of June 30, 2023, there were approximately 527 holders of record of our ordinary shares, which does not include beneficial owners holding our securities through nominee names.
History of Share Capital
In February 2023, we issued 128,444,000 ordinary shares at $1.27 per share for aggregate gross proceeds of $163 million, before deducting the underwriting discount. The aggregate underwriting discount to the bookrunners was approximately $8.5 million. The issuance and sale included (i) a placement with Qualified Investors within the meaning of Article 2(E) of Regulation (EU) 2017/1129 and (ii) a retail offer made available only to existing shareholders of the Company in the UK. Stifel Nicolaus Europe Limited, Tennyson Securities Limited and Peel Hunt LLP acted as joint global coordinators and bookrunners.
In May 2021, we issued 141,540,782 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 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 64,280,500 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.
 
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Since March 31, 2020, we have granted (i) an aggregate of 14,845,109 restricted stock units to our employees and (ii) an aggregate of 23,677,666 performance stock units to our employees.
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.
We, any of our shareholders or any other affected person may apply to the court for rectification of the share register if:
•
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 May 2, 2023, our shareholders approved the exclusion of preemptive rights, for an aggregate nominal value of up to £1,942,820, representing not more than 20% of the issued share capital as at March 21, 2023, subject to certain conditions, with such authority expiring at the conclusion of our next annual general meeting or, if earlier, June 30, 2024. 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, 2024) to remain effective, but may be sought more frequently for additional five-year terms (or any shorter period).
Options
As of December 31, 2022, there were options to purchase 7,513,331 ordinary shares outstanding with a weighted-average exercise price of £0.96 per share, and as of June 30, 2023, there were options to purchase 4,784,274 ordinary shares outstanding with a weighted-average exercise price of £1.02 per share. These options lapse after ten years from the date of the grant.
 
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B.   Memorandum and Articles of Association
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 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.
For so long as any shares are held in a settlement system operated by DTC and a DTC Depositary holds legal title to shares in our capital for DTC, (i) any resolution put to the vote of a general meeting must be decided on a poll. Subject to the foregoing, 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
​
 
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•
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) 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 the Company. For additional information permissible actions by the Company’s directors with respect to Default Shares, see below under the subsection titled “— Other UK Law Considerations — Disclosure of Interest in Shares.” 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; provided, however, the board of directors may waive these restrictions, in whole or in part, at any time.
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
 
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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.
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
 
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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:
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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;
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•
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
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•
in respect of only one class of shares.
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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 to hold an annual general meeting each year in addition to any other general meetings in that year and to specify the meeting as such in the notice
 
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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:
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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);
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•
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
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•
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.
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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.
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 our Articles of Association.
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:
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he is recommended by the board of directors; or
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•
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.
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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:
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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;
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•
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;
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•
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;
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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 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
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•
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.
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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
 
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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 Articles 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:
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•
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
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•
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;
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•
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;
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•
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;
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•
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;
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•
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.
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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 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 £1,055,000 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
 
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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 provision of our 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:
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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.
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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 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:
(a)   indemnify any director of the Company (or of an associated body corporate) against any liability;
(b)   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;
(c)   purchase and maintain insurance against any liability for any director referred to in paragraph (a) or (b) above; and
 
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(d)   provide any director referred to in paragraphs (a) or (b) 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 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
 
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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).
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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.
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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 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.
 
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It is not sufficient that we, as a UK 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 UK 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
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•
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.
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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:
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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; or
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•
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,
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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, other than withholding tax requirements. There is no limitation imposed by UK 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 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.
 
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United Kingdom
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Delaware
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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
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Delaware
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General Meeting
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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 ​
 
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Delaware
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​ ​ ​ ​ ​ ​ 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 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. ​ ​ 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, 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
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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
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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:
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any breach of the director’s duty of loyalty to the corporation or its stockholders;
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​ ​ ​ 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 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). ​ ​
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acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;
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intentional or negligent payment of unlawful dividends or stock purchases or redemptions; or
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any transaction from which the director derives an improper personal benefit.
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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 ​ ​ 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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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 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.
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Shareholder Vote on Certain Transactions
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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:
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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
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the approval of the court.
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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:
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the approval of the board of directors; and
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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.
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Standard of Conduct for Directors
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Under UK law, a director owes various statutory and fiduciary duties to the company, including:
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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;
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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;
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to act in accordance with the company’s constitution and only exercise his powers for the purposes for which they are conferred;
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to exercise independent judgment;
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to exercise reasonable care, skill and diligence;
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not to accept benefits from a third party conferred by reason of his being a director or doing, or not doing, anything as a director; and
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a duty to declare any interest that he has, whether directly or indirectly, in a proposed or existing transaction or arrangement with the company.
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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.
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
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​ ​ ​ ​ ​ ​ 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:
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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
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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.
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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.
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Listing
We intend to apply to have our ordinary shares listed on the NYSE under the symbol “DEC.”
C.   Material Contracts
Our material contracts include:
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Participation Agreement, dated October 2, 2020, by and between Diversified Production LLC and OCM Denali Holdings, LLC.
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Letter Agreement, dated January 12, 2022, by and between Diversified Production LLC and OCM Denali Holdings, LLC.
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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Second Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated June 28, 2019, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association,
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as administrative agent, the guarantors party thereto and the lenders party thereto. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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Twelfth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated August 17, 2021, among the Diversified Gas & Oil Corporation, as borrower, KeyBank National
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Association, as administrative agent, the guarantors party thereto and the lenders party thereto. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5.B Liquidity.”
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First Amendment to Amended and Restated Revolving Credit Agreement, dated as of March 1, 2023 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. For a description of this contract, see “Item 5.B Liquidity.”
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Second Amendment to Amended and Restated Revolving Credit Agreement, dated as of April 27, 2023 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. For a description of this contract, see “Item 5.B Liquidity.”
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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, as amended. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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Indenture, dated November 13, 2019, by and between Diversified ABS LLC, as issuer, and UMB Bank, N.A., as indenture trustee and securities intermediary. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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First Amendment to Indenture, dated February 13, 2020, by and between Diversified ABS LLC, as issuer, and UMB Bank, N.A., as indenture trustee. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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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. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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Indenture, dated October 27, 2022, among Diversified ABS Phase VI LLC, as issuer, Diversified ABS VI Upstream LLC and Oaktree ABS VI Upstream LLC, as guarantors and UMB Bank, N.A., as indenture trustee and securities intermediary. For a description of this contract, see “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.”
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Service Agreement, dated January 30, 2017, by and between Diversified Gas & Oil plc and Rusty Hutson
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Service Agreement, dated January 30, 2017, by and between Diversified Gas & Oil plc and Bradley Gray
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2017 Equity Incentive Plan, as amended.
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D.   Exchange Controls
Other than certain economic sanctions which may be in place from time to time, there are currently no UK laws, decrees or regulations restricting the import or export of capital or affecting the remittance of dividends or other payment to holders of ordinary shares who are non-residents of the United Kingdom. Similarly, other than certain economic sanctions which may be in force from time to time, there are no limitations relating only to nonresidents of the United Kingdom under English law or the Company’s articles of association on the right to be a holder of, and to vote in respect of, the ordinary shares.
E.   Taxation
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 ordinary shares. They are based on current UK tax law and on the current published practice of His Majesty’s Revenue and Customs (“HMRC”) (which may not be binding on HMRC), as of the date of this registration statement, all of which are subject to change, possibly with retrospective effect. They are intended to address only certain UK tax consequences for holders of ordinary shares 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 ordinary shares and any dividends paid on them and who hold the ordinary shares 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 shareholders 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 ordinary shares as part of hedging or conversion transactions, shareholders who have (or are deemed to have) acquired their ordinary shares by virtue of an office or employment, and shareholders who are or have been officers or employees of the Company. The statements do not apply to any shareholder 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 ordinary shares.
 
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Accordingly, prospective subscribers for, or purchasers of, any ordinary shares who are in any doubt as to their tax position regarding the acquisition, ownership or disposition of any ordinary shares 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 a shareholder.
Income tax
An individual shareholder 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 shareholder 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 ordinary shares 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 ordinary shares from the Company or from other sources will form part of the shareholder’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 £1,000 (reducing to £500 from 6 April 2024) of taxable dividend income received by the shareholder 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 £1,000 dividend allowance, the first £1,000 of the dividend income will be charged at the nil rate and any excess amount will be taxed at 8.75% to the extent that the excess amount falls within the basic rate tax band, 33.75% to the extent that the excess amount falls within the higher rate tax band and 39.35% to the extent that the excess amount falls within the additional rate tax band.
Corporation tax
Corporate shareholders 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 a shareholder elects for an otherwise exempt dividend to be taxable, the shareholder will be subject to UK corporation tax on dividends received from the Company, at the rate of corporation tax applicable to that shareholder (the main rate of UK corporation tax is currently 25%).
Corporate shareholders 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 ordinary shares 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 chargeable gains
UK resident shareholders
A disposal or deemed disposal of ordinary shares by an individual or corporate shareholder who is tax resident in the United Kingdom may, depending on the shareholder’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.
 
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Any chargeable gain (or allowable loss) will generally be calculated by reference to the consideration received for the disposal of the ordinary shares less the allowable cost to the shareholder of acquiring any such ordinary shares.
The applicable tax rates for individual shareholders realizing a gain on the disposal of ordinary shares is, broadly, 10% for basic rate taxpayers and 20% for higher and additional rate taxpayers. For corporate shareholders, corporation tax is generally charged on chargeable gains at the rate applicable to the relevant corporate shareholder.
Non-UK shareholders
Shareholders who are not resident in the United Kingdom and, in the case of an individual shareholder, not temporarily non-resident, should not be liable for UK tax on capital gains realized on a sale or other disposal of ordinary shares unless (i) such ordinary shares 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 shareholder, through a permanent establishment or (ii) where certain conditions are met, the Company derives 75% or more of its gross value from UK land. Shareholders who are not resident in the United Kingdom may be subject to non-UK taxation on any gain under local law.
Generally, an individual shareholder 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 ordinary shares 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 shareholder 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 rate or may, although not primarily liable for the tax, be required to notify and account for it under the UK Stamp Duty Reserve Tax Regulations 1986. The discussion below does not consider any potential change of law.
Issue of shares
As a general rule (and except in relation to depositary receipt systems and clearance services (as to which see below)), no stamp duty or SDRT is payable on the issue of the ordinary shares.
Clearance systems and depositary receipt issuers
An unconditional agreement to issue or 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, in the context of a clearance service, 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, HMRC clearance has been received by the Company confirming that no stamp duty or SDRT is payable on the transfer of legal title to the existing ordinary shares into the DTC clearing system, to the extent required in order to implement the U.S. Listing at the effective time. Such HMRC clearance only applies to transfers into the DTC clearing system made on the Initial Depositary Transfer Date in order to implement the U.S. Listing (and transfers of ordinary shares held by Restricted Shareholders which are transferred to Computershare Trust Company N.A. (as depositary for the holders of the Restricted Shares) on the Initial Depositary Transfer Date), and not subsequent transfers into the DTC clearing system (other than certain transfers of ordinary shares held by Restricted Shareholders on the Initial Depositary Transfer Date).
 
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Transfer of shares and DIs
No SDRT should be required to be paid on a paperless transfer of ordinary shares through the clearance service facilities of DTC, provided that no section 97A election has been made by DTC, and such ordinary shares are held through DTC at the time of any agreement for their transfer.
No stamp duty will in practice be payable on a written instrument transferring an ordinary share 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 ordinary share could, depending on the circumstances, attract a charge to 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.
The Company has received HMRC clearance confirming that agreements to transfer DIs which represent ordinary shares held within the DTC clearance system will not be subject to SDRT.
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 ordinary share issued pursuant to this listing, 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 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 ordinary share. 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 court will not take a contrary position to that discussed below regarding the tax consequences of the purchase, ownership and disposition of our ordinary shares.
This discussion is limited to U.S. Holders and Non-U.S. Holders that each hold an ordinary share 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:
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U.S. expatriates and former citizens or long-term residents of the United States;
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U.S. Holders (as defined below) whose functional currency is not the U.S. dollar;
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persons holding an ordinary share as part of a hedge, straddle or other risk reduction strategy or as part of a conversion transaction or other integrated investment;
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banks, insurance companies, and other financial institutions;
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brokers, dealers or traders in securities;
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“controlled foreign corporations,” passive foreign investment companies,” and corporations that accumulate earnings to avoid U.S. federal income tax;
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partnerships or other entities or arrangements treated as partnerships for U.S. federal income tax purposes and other pass-through entities (and investors therein);
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tax-exempt organizations or governmental organizations;
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persons deemed to sell an ordinary share under the constructive sale provisions of the Code;
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persons who hold or receive an ordinary share pursuant to the exercise of any employee stock option or otherwise as compensation;
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tax qualified retirement plans;
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•
“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
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persons subject to special tax accounting rules as a result of any item of gross income with respect to the ordinary shares being taken into account in an applicable financial statement.
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If an entity or arrangement treated as a partnership for U.S. federal income tax purposes holds an ordinary share, 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 ordinary share 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 ORDINARY SHARE 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.
U.S. Holders
For purposes of this discussion, a “U.S. Holder” is any beneficial owner of an ordinary share that, for U.S. federal income tax purposes, is or is treated as any of the following:
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an individual who is a citizen or resident of the United States;
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a corporation created or organized under the laws of the United States, any state thereof, or the District of Columbia;
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an estate, the income of which is subject to U.S. federal income tax regardless of its source; or
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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.
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Distributions
Distributions, if any, made on the ordinary shares, 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 ordinary shares and thereafter as capital gain from the sale or exchange of such ordinary shares. 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 Ordinary Shares
Upon the sale, certain redemption or other taxable disposition of an ordinary share, 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 ordinary shares. Any gain or loss recognized on a taxable disposition of an ordinary share will be capital gain or loss. Such capital gain or loss will be long-term capital gain or loss if a U.S.
 
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Holder’s holding period at the time of the sale, redemption or other taxable disposition of the ordinary shares 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 ordinary share 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 ordinary shares, 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 ordinary shares, 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’ ordinary shares constitute a USRPI (as defined below). However, we 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’ ordinary shares do not constitute a USRPI. For additional information regarding when a Non-U.S. Holder may treat its ownership of the ordinary shares 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 ordinary share 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 ordinary share unless:
 
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•
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);
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•
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
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our ordinary shares constitute 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.
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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 ordinary shares, 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.
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 ordinary shares constitute (and we expect the ordinary shares 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 ordinary shares, 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 ordinary shares 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 ordinary shares 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 ordinary shares 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 ordinary shares, even if such ordinary shares constitute USRPIs. Moreover, if the ordinary shares 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 ordinary shares taking into account applicable constructive ownership rules, such Non-U.S. Holder may treat its ownership of the ordinary shares 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 ordinary shares (in addition to not being subject to the 15% withholding tax described above) or U.S. tax return filing requirements. The Company expects the ordinary shares to be treated as “regularly traded on an established securities market” so long as the ordinary shares are listed on the NYSE and regularly quoted by brokers or dealers making a market in such ordinary shares.
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 ordinary shares and the proceeds of a sale of an ordinary share paid to a U.S. Holder unless the U.S. Holder is an
 
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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 ordinary shares 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 ordinary shares 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 ordinary shares 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 ordinary shares conducted through a non-U.S. office of a non-U.S. broker generally will not be subject to backup withholding or information reporting.
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 ordinary shares 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 ordinary shares. While withholding under FATCA would have applied also to payments of gross proceeds from the sale or other disposition of stock, including our ordinary shares, 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.
 
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Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our ordinary shares.
F.   Dividends and Paying Agents
For a discussion of the declaration and payment of dividends on our ordinary shares, see “Item 10. Additional Information — B. Memorandum and Articles of Association — Distributions and Dividends.”
G.   Statement by Experts
The financial statements as of December 31, 2022 and 2021 and for each of the three years in the period ended December 31, 2022 included in this registration statement on Form 20-F 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.
Independent Petroleum Engineers
The letter reports, included as an exhibit to this registration statement, 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 registration statement 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.
H.   Documents on Display
Upon the effectiveness of this registration statement, the Company will be subject to the information reporting requirements of the Exchange Act applicable to foreign private issuers, and under those requirements will file reports with the SEC. Those other reports or other information and this registration statement may be inspected without charge and copied at the public reference facilities of the SEC located at 100 F Street, N.E., Washington, D.C. 20549. The SEC also maintains a website at http://www.sec.gov from which certain filings may be accessed. We also make our electronic filings with the SEC available at no cost on the Group’s Investor Relations website, www.ir.div.energy, as soon as reasonably practicable after we file such material with, or furnish it to, the SEC.
As a foreign private issuer, we will be exempt from the rules under the Exchange Act related to the furnishing and content of proxy statements, and our officers, directors and principal shareholders will be 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 annual, quarterly and current reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act. However, for so long as we are listed on a U.S. exchange and are registered with the SEC, we will file with the SEC, within 4 months after the end of each fiscal year, or such applicable time as required by the SEC, an annual report on Form 20-F containing financial statements audited by an independent registered public accounting firm, and will furnish to the SEC, on a Form 6-K, all financial statements and other information required to be furnished on Form 6-K. We will also make available on our website, free of charge, our annual reports on Form 20-F and the text of our reports on Form 6-K, including any amendments to these reports, as well as certain other SEC filings, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Our website address is www.div.energy. The information contained on our website is not incorporated by reference in this document.
I.   Subsidiary Information
Not applicable.
J.   Annual Report to Securities Holders
Not applicable.
 
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Item 11.   Quantitative and Qualitative Disclosures About Market Risk
See “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.” In addition to the risks inherent in our operations, we are exposed to a variety of financial risks, such as market risk (including foreign currency exchange, cash flow and interest rate risk), credit risk and liquidity risk. Further information can be found under Note 25 included in “Item 18. Financial Statements — Audited Consolidated Financial Statements.”
b.   Qualitative Information about Market Risk
See “Item 5. Operating and Financial Results and Prospects — B. Liquidity and Capital Resources.” In addition to the risks inherent in our operations, we are exposed to a variety of financial risks, such as market risk (including foreign currency exchange, cash flow and interest rate risk), credit risk and liquidity risk. Further information can be found under Note 25 included in “Item 18. Financial Statements — Audited Consolidated Financial Statements.”
Item 12.   Description of Securities Other than Equity Securities
A.   Debt Securities
Not applicable.
B.   Warrants and Rights
Not applicable.
C.   Other Securities
Not applicable.
D.   American Depositary Shares
Not applicable.
 
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PART II
Item 13.   Defaults, Dividend Arrearages and Delinquencies
Not applicable.
Item 14.   Material Modifications to the Rights of Security Holders and Use of Proceeds
Not applicable.
Item 15.   Controls and Procedures
Not applicable.
Item 16.   [Reserved]
Item 16A.   Audit Committee Financial Expert
Not applicable.
Item 16B.   Code of Ethics
Not applicable.
Item 16C.   Principal Accountant Fees and Services
Not applicable.
Item 16D.   Exemptions from the Listing Standards for Audit Committees
Not applicable.
Item 16E.   Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Not applicable.
Item 16F.   Change in Registrant’s Certifying Accountant
None.
Item 16G.   Corporate Governance
Not applicable.
Item 16H.   Mine Safety Disclosure
Not applicable.
Item 16I.   Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
 
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PART III
Item 17.   Financial Statements
We have elected to furnish financial statements and related information specified in Item 18.
Item 18.   Financial Statements
The audited consolidated financial statements as required under Item 18 are attached hereto starting on page F-1 of this Registration Statement. The audit report of Pricewaterhouse Coopers LLP, an independent registered public accounting firm, is included herein preceding the audited consolidated financial statements.
Item 19.   Exhibits
List all exhibits filed as part of the registration statement or annual report, including exhibits incorporated by reference.
​
Exhibit 
No.
​ ​
Description
​
​ 1.1# ​ ​ ​
​ 1.2# ​ ​ ​
​ 2.1# ​ ​ ​
​ 4.1#X ​ ​ ​
​ 4.2#X ​ ​ ​
​ 4.3#X ​ ​ ​
​ 4.4#X ​ ​ ​
​ 4.5#X ​ ​ ​
​ 4.6#X ​ ​ ​
​ 4.7#X ​ ​ ​
​ 4.8#X ​ ​ ​
 
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​
Exhibit 
No.
​ ​
Description
​
​ 4.9#X ​ ​ ​
​ 4.10#X ​ ​ ​
​ 4.11#X ​ ​ ​
​ 4.12#X ​ ​ ​
​ 4.13#X ​ ​ ​
​ 4.14#X ​ ​ ​
​ 4.15#X ​ ​ ​
​ 4.16#X ​ ​ ​
​ 4.17#X ​ ​ ​
​ 4.18#X ​ ​ ​
​ 4.19#X ​ ​ ​
​ 4.20#X ​ ​ ​
 
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​
Exhibit 
No.
​ ​
Description
​
​ 4.21#X ​ ​ First Amendment to Amended and Restated Revolving Credit Agreement, dated March 1, 2023 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. ​
​ 4.22#X ​ ​ Second Amendment to Amended and Restated Revolving Credit Agreement, dated April 27, 2023 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. ​
​ 4.23#X ​ ​ ​
​ 4.24#X† ​ ​ ​
​ 4.25#X† ​ ​ ​
​ 4.26#X† ​ ​ ​
​ 4.27#X† ​ ​ ​
​ 4.28#X† ​ ​ ​
​ 4.29#X† ​ ​ ​
​ 4.30#X† ​ ​ ​
​ 4.31*# ​ ​ ​
​ 4.32*# ​ ​ ​
​ 4.33# ​ ​ ​
​ 4.34# ​ ​ ​
​ 8.1# ​ ​ ​
​ 15.1# ​ ​ ​
​ 15.2# ​ ​ ​
​ 15.3# ​ ​ ​
​ 15.4# ​ ​ ​
​ 15.5# ​ ​ 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. ​
​
†
Certain portions of this exhibit (indicated by “[***]”) have been redacted.
​
 
159
 
X
Certain of the schedules and attachments to this exhibit have been omitted. The registrant hereby undertakes to provide further information regarding such omitted materials to the Commission upon request.
​
*
Management Contract
​
+
Previously filed
​
#
Filed herewith
​
Certain agreements filed as exhibits to this registration statement contain representations and warranties that the parties thereto made to each other. These representations and warranties have been made solely for the benefit of the other parties to such agreements and may have been qualified by certain information that has been disclosed to the other parties to such agreements and that may not be reflected in such agreements. In addition, these representations and warranties may be intended as a way of allocating risks among parties if the statements contained therein prove to be incorrect, rather than as actual statements of fact. Accordingly, there can be no reliance on any such representations and warranties as characterizations of the actual state of facts. Moreover, information concerning the subject matter of any such representations and warranties may have changed since the date of such agreements.
 
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SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this registration statement on its behalf.
DIVERSIFIED ENERGY COMPANY PLC
Date: November 16, 2023
By:
/s/ Bradley G. Gray
​
​
Name:
Bradley G. Gray
​
Title:
President & Chief Financial Officer
​
 
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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
F-1
 
DIVERSIFIED ENERGY COMPANY PLC
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS (AUDITED)
​ ​ ​
Page
​
​ ​ ​ ​ F-3 ​ ​
​ ​ ​ ​ F-5 ​ ​
​ ​ ​ ​ F-6 ​ ​
​ ​ ​ ​ F-7 ​ ​
​ ​ ​ ​ F-8 ​ ​
​ ​ ​ ​ F-10 ​ ​
 
F-2
 
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of 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, 2022 and 2021, and the related consolidated statements of comprehensive income, of changes in equity, and of cash flows for each of the three years in the period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 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. 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.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Natural Gas, Oil, and Natural Gas Liquids (NGL) Reserves on Natural Gas and Oil Properties, Net
As described in Notes 3, 4 and 10 to the consolidated financial statements, the Company’s natural gas and oil properties, net balance was $2.56 billion as of December 31, 2022, and the related depletion expense for the year ended December 31, 2022 was $170 million. Natural gas and oil activities are accounted for using the principles of the successful efforts method of accounting. Costs incurred to purchase, lease, or otherwise acquire a property are capitalized when incurred. Proved natural gas, oil and NGL reserve volumes are used as the basis to calculate unit-of-production depletion rates. In estimating proved natural gas, oil and NGL reserves, management relies on interpretations and judgment of available geological, geophysical,
 
F-3
 
engineering and production data, as well as the use of certain economic assumptions such as commodity pricing. Additional assumptions include operating expenses, capital expenditures, and taxes. As disclosed by management, the Company’s internal staff of petroleum engineers and geoscience professionals work closely with the independent reserve engineers (together referred to as “management’s specialists”).
The principal considerations for our determination that performing procedures relating to the impact of proved natural gas, oil and NGL reserves on proved natural gas and oil properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved natural gas, oil and NGL reserve volumes, as the reserve volumes are based on engineering assumptions and methods and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved natural gas, oil and NGL reserve volumes and the assumptions applied to commodity pricing and operating expenses.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved natural gas, oil and NGL reserve volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing the completeness and accuracy of the data used by the specialists, and evaluating the specialists’ findings. These procedures also included, among others, testing the completeness and accuracy of the underlying data related to commodity pricing and operating expenses. Additionally, these procedures included evaluating whether the assumptions applied to the data related to commodity pricing and operating expenses that were used in developing the estimate of proved natural gas, oil and NGL reserve volumes were reasonable considering the past performance of the Company.
/s/ PricewaterhouseCoopers LLP
Birmingham, Alabama
November 16, 2023
We have served as the Company’s auditor since 2020.
 
F-4
 
Consolidated Statement of Comprehensive Income
(Amounts in thousands, except per share and per unit data)
​ ​ ​ ​ ​ ​
Year Ended
​
​ ​ ​
Notes
​ ​
December 31, 2022
​ ​
December 31, 2021
​ ​
31 December 2020
​
Revenue
​ ​
6
​ ​ ​ $ 1,919,349 ​ ​ ​ ​ $ 1,007,561 ​ ​ ​ ​ $ 408,693 ​ ​
Operating expense
​ ​
7
​ ​ ​ ​ (445,893) ​ ​ ​ ​ ​ (291,213) ​ ​ ​ ​ ​ (203,963) ​ ​
Depreciation, depletion and amortization
​ ​
7
​ ​ ​ ​ (222,257) ​ ​ ​ ​ ​ (167,644) ​ ​ ​ ​ ​ (117,290) ​ ​
Gross profit
​ ​ ​ ​ ​ ​ $ 1,251,199 ​ ​ ​ ​ $ 548,704 ​ ​ ​ ​ $ 87,440 ​ ​
General and administrative expense
​ ​
7
​ ​ ​ ​ (170,735) ​ ​ ​ ​ ​ (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
​ ​ ​ ​ 2,379 ​ ​ ​ ​ ​ (901) ​ ​ ​ ​ ​ (2,059) ​ ​
Gain (loss) on derivative financial instruments
​ ​
13
​ ​ ​ ​ (1,758,693) ​ ​ ​ ​ ​ (974,878) ​ ​ ​ ​ ​ (94,397) ​ ​
Gain on bargain purchases
​ ​
5
​ ​ ​ ​ 4,447 ​ ​ ​ ​ ​ 58,072 ​ ​ ​ ​ ​ 17,172 ​ ​
Operating profit (loss)
​ ​ ​ ​ ​ ​ $ (671,403) ​ ​ ​ ​ $ (467,064) ​ ​ ​ ​ $ (77,568) ​ ​
Finance costs
​ ​
21
​ ​ ​ ​ (100,799) ​ ​ ​ ​ ​ (50,628) ​ ​ ​ ​ ​ (43,327) ​ ​
Accretion of asset retirement obligation
​ ​
19
​ ​ ​ ​ (27,569) ​ ​ ​ ​ ​ (24,396) ​ ​ ​ ​ ​ (15,424) ​ ​
Other income (expense)
​ ​ ​ ​ ​ ​ ​ 269 ​ ​ ​ ​ ​ (8,812) ​ ​ ​ ​ ​ (421) ​ ​
Income (loss) before taxation
​ ​ ​ ​ ​ ​ $ (799,502) ​ ​ ​ ​ $ (550,900) ​ ​ ​ ​ $ (136,740) ​ ​
Income tax benefit (expense)
​ ​
8
​ ​ ​ ​ 178,904 ​ ​ ​ ​ ​ 225,694 ​ ​ ​ ​ ​ 113,266 ​ ​
Net income (loss)
​ ​ ​ ​ ​ ​ $ (620,598) ​ ​ ​ ​ $ (325,206) ​ ​ ​ ​ $ (23,474) ​ ​
Other comprehensive income (loss)
​ ​ ​ ​ ​ ​ ​ 940 ​ ​ ​ ​ ​ 51 ​ ​ ​ ​ ​ (28) ​ ​
Total comprehensive income (loss)
​ ​ ​ ​ ​ ​ $ (619,658) ​ ​ ​ ​ $ (325,155) ​ ​ ​ ​ $ (23,502) ​ ​
Net income (loss) attributable to: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Diversified Energy Company PLC
​ ​ ​ ​ ​ ​ $ (625,410) ​ ​ ​ ​ $ (325,509) ​ ​ ​ ​ $ (23,474) ​ ​
Non-controlling interest
​ ​ ​ ​ ​ ​ ​ 4,812 ​ ​ ​ ​ ​ 303 ​ ​ ​ ​ ​ — ​ ​
Net income (loss)
​ ​ ​ ​ ​ ​ $ (620,598) ​ ​ ​ ​ $ (325,206) ​ ​ ​ ​ $ (23,474) ​ ​
Earnings (loss) per share attributable to Diversified Energy Company PLC
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Weighted average shares outstanding – basic and
diluted
​ ​
10
​ ​ ​ ​ 844,080 ​ ​ ​ ​ ​ 793,542 ​ ​ ​ ​ ​ 685,170 ​ ​
Earnings (loss) per share – basic and diluted
​ ​
9
​ ​ ​ $ (0.74) ​ ​ ​ ​ $ (0.41) ​ ​ ​ ​ $ (0.03) ​ ​
The notes are an integral part of the Consolidated Financial Statements.
F-5
 
Consolidated Statement of Financial Position
(Amounts in thousands, except per share and per unit data)
​ ​ ​
Notes
​ ​
December 31, 2022
​ ​
December 31, 2021
​
ASSETS ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Non-current assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas and oil properties, net
​ ​
10
​ ​ ​ $ 2,555,808 ​ ​ ​ ​ $ 2,530,078 ​ ​
Property, plant and equipment, net
​ ​
11
​ ​ ​ ​ 462,860 ​ ​ ​ ​ ​ 413,980 ​ ​
Intangible assets
​ ​
12
​ ​ ​ ​ 21,098 ​ ​ ​ ​ ​ 14,134 ​ ​
Restricted cash
​ ​
3
​ ​ ​ ​ 47,497 ​ ​ ​ ​ ​ 18,069 ​ ​
Derivative financial instruments
​ ​
13
​ ​ ​ ​ 13,936 ​ ​ ​ ​ ​ 219 ​ ​
Deferred tax assets
​ ​
8
​ ​ ​ ​ 371,156 ​ ​ ​ ​ ​ 176,955 ​ ​
Other non-current assets
​ ​
15
​ ​ ​ ​ 4,351 ​ ​ ​ ​ ​ 3,635 ​ ​
Total non-current assets
​ ​ ​ ​ ​ ​ $ 3,476,706 ​ ​ ​ ​ $ 3,157,070 ​ ​
Current assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Trade receivables, net
​ ​
14
​ ​ ​ $ 296,781 ​ ​ ​ ​ $ 282,922 ​ ​
Cash and cash equivalents
​ ​
3
​ ​ ​ ​ 7,329 ​ ​ ​ ​ ​ 12,558 ​ ​
Restricted cash
​ ​
3
​ ​ ​ ​ 7,891 ​ ​ ​ ​ ​ 1,033 ​ ​
Derivative financial instruments
​ ​
13
​ ​ ​ ​ 27,739 ​ ​ ​ ​ ​ 1,052 ​ ​
Other current assets
​ ​
15
​ ​ ​ ​ 14,482 ​ ​ ​ ​ ​ 39,574 ​ ​
Total current assets
​ ​ ​ ​ ​ ​ $ 354,222 ​ ​ ​ ​ $ 337,139 ​ ​
Total assets
​ ​ ​ ​ ​ ​ $ 3,830,928 ​ ​ ​ ​ $ 3,494,209 ​ ​
EQUITY AND LIABILITIES ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Shareholders’ equity:
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Share capital
​ ​
16
​ ​ ​ $ 11,503 ​ ​ ​ ​ $ 11,571 ​ ​
Share premium
​ ​
16
​ ​ ​ ​ 1,052,959 ​ ​ ​ ​ ​ 1,052,959 ​ ​
Treasury reserve
​ ​ ​ ​ ​ ​ ​ (100,828) ​ ​ ​ ​ ​ (68,537) ​ ​
Share based payment and other reserves
​ ​ ​ ​ ​ ​ ​ 17,650 ​ ​ ​ ​ ​ 14,156 ​ ​
Retained earnings (accumulated deficit)
​ ​ ​ ​ ​ ​ ​ (1,133,972) ​ ​ ​ ​ ​ (362,740) ​ ​
Equity attributable to owners of the parent:
​ ​ ​ ​ ​ ​ $ (152,688) ​ ​ ​ ​ $ 647,409 ​ ​
Non-controlling interests
​ ​
5
​ ​ ​ ​ 14,964 ​ ​ ​ ​ ​ 16,541 ​ ​
Total equity
​ ​ ​ ​ ​ ​ $ (137,724) ​ ​ ​ ​ $ 663,950 ​ ​
Non-current liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Asset retirement obligations
​ ​
19
​ ​ ​ $ 452,554 ​ ​ ​ ​ $ 522,190 ​ ​
Leases
​ ​
20
​ ​ ​ ​ 19,569 ​ ​ ​ ​ ​ 18,177 ​ ​
Borrowings
​ ​
21
​ ​ ​ ​ 1,169,233 ​ ​ ​ ​ ​ 951,535 ​ ​
Deferred tax liability
​ ​
8
​ ​ ​ ​ 12,490 ​ ​ ​ ​ ​ — ​ ​
Derivative financial instruments
​ ​
13
​ ​ ​ ​ 1,177,801 ​ ​ ​ ​ ​ 556,982 ​ ​
Other non-current liabilities
​ ​
23
​ ​ ​ ​ 5,375 ​ ​ ​ ​ ​ 7,775 ​ ​
Total non-current liabilities
​ ​ ​ ​ ​ ​ $ 2,837,022 ​ ​ ​ ​ $ 2,056,659 ​ ​
Current liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Trade and other payables
​ ​
22
​ ​ ​ $ 93,764 ​ ​ ​ ​ $ 62,418 ​ ​
Leases
​ ​
20
​ ​ ​ ​ 9,293 ​ ​ ​ ​ ​ 9,627 ​ ​
Borrowings
​ ​
21
​ ​ ​ ​ 271,096 ​ ​ ​ ​ ​ 58,820 ​ ​
Derivative financial instruments
​ ​
13
​ ​ ​ ​ 293,840 ​ ​ ​ ​ ​ 251,687 ​ ​
Other current liabilities
​ ​
23
​ ​ ​ ​ 463,637 ​ ​ ​ ​ ​ 391,048 ​ ​
Total current liabilities
​ ​ ​ ​ ​ ​ $ 1,131,630 ​ ​ ​ ​ $ 773,600 ​ ​
Total liabilities
​ ​ ​ ​ ​ ​ $ 3,968,652 ​ ​ ​ ​ $ 2,830,259 ​ ​
Total equity and liabilities
​ ​ ​ ​ ​ ​ $ 3,830,928 ​ ​ ​ ​ $ 3,494,209 ​ ​
The Consolidated Financial Statements were approved and authorized for issue by the Board on May 1, 2023 and were signed on its behalf by:
[MISSING IMAGE: sg_davidejohnson-bw.jpg]
DAVID E. JOHNSON
Chairman of the Board
May 1, 2023
The notes are an integral part of the Consolidated Financial Statements.
F-6
 
Consolidated Statement of Changes in Equity
(Amounts in thousands, except per share and per unit data)
​ ​ ​
Notes
​ ​
Share
Capital
​ ​
Share
Premium
​ ​
Treasury
Reserve
​ ​
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 January 1, 2020
​ ​ ​ ​ ​ ​ $ 8,800 ​ ​ ​ ​ $ 760,543 ​ ​ ​ ​ $ (52,903) ​ ​ ​ ​ $ 3,947 ​ ​ ​ ​ $ 217,748 ​ ​ ​ ​ $ 938,135 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ 938,135 ​ ​
Income (loss) after taxation
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (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 (equity placement)
​ ​
16
​ ​ ​ ​ 791 ​ ​ ​ ​ ​ 80,616 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 81,407 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 81,407 ​ ​
Issuance of share capital (equity compensation)
​ ​ ​ ​ ​ ​ ​ 3 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4,776 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4,779 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4,779 ​ ​
Repurchase of shares (share buyback
program)
​ ​
16
​ ​ ​ ​ (74) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (15,634) ​ ​ ​ ​ ​ 74 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (15,634) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (15,634) ​ ​
Dividends
​ ​
18
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (98,527) ​ ​ ​ ​ ​ (98,527) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (98,527) ​ ​
Transactions with shareholders
​ ​ ​ ​ ​ ​ $ 720 ​ ​ ​ ​ $ 80,616 ​ ​ ​ ​ $ (15,634) ​ ​ ​ ​ $ 4,850 ​ ​ ​ ​ $ (98,527) ​ ​ ​ ​ $ (27,975) ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (27,975) ​ ​
Balance as of December 31, 2020
​ ​ ​ ​ ​ ​ $ 9,520 ​ ​ ​ ​ $ 841,159 ​ ​ ​ ​ $ (68,537) ​ ​ ​ ​ $ 8,797 ​ ​ ​ ​ $ 95,719 ​ ​ ​ ​ $ 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 in acquired assets
​ ​
5
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 16,238 ​ ​ ​ ​ ​ 16,238 ​ ​
Issuance of share capital (equity placement)
​ ​
16
​ ​ ​ ​ 2,044 ​ ​ ​ ​ ​ 211,800 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 213,844 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 213,844 ​ ​
Issuance of share capital (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 ​ ​ ​ ​ $ (68,537) ​ ​ ​ ​ $ 14,156 ​ ​ ​ ​ $ (362,740) ​ ​ ​ ​ $ 647,409 ​ ​ ​ ​ $ 16,541 ​ ​ ​ ​ $ 663,950 ​ ​
Net Income (loss)
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (625,410) ​ ​ ​ ​ ​ (625,410) ​ ​ ​ ​ ​ 4,812 ​ ​ ​ ​ ​ (620,598) ​ ​
Other comprehensive income (loss)
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 940 ​ ​ ​ ​ ​ 940 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 940 ​ ​
Total comprehensive income (loss)
​ ​ ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (624,470) ​ ​ ​ ​ $ (624,470) ​ ​ ​ ​ $ 4,812 ​ ​ ​ ​ $ (619,658) ​ ​
Issuance of share capital (settlement of warrants)
​ ​
16
​ ​ ​ ​ 5 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 452 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 457 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 457 ​ ​
Issuance of share capital (equity compensation)
​ ​ ​ ​ ​ ​ ​ 7 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 5,682 ​ ​ ​ ​ ​ (3,307) ​ ​ ​ ​ ​ 2,382 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2,382 ​ ​
Issuance of EBT shares (equity compensation)
​ ​
16
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2,400 ​ ​ ​ ​ ​ (2,400) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares (EBT)
​ ​
16
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (22,931) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (22,931) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (22,931) ​ ​
Repurchase of shares (share buyback
program)
​ ​
16
​ ​ ​ ​ (80) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (11,760) ​ ​ ​ ​ ​ 80 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (11,760) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (11,760) ​ ​
Dividends
​ ​
18
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (143,455) ​ ​ ​ ​ ​ (143,455) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (143,455) ​ ​
Distributions to non-controlling interest owners
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (6,389) ​ ​ ​ ​ ​ (6,389) ​ ​
Cancellation of warrants
​ ​
16
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (320) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (320) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (320) ​ ​
Transactions with shareholders
​ ​ ​ ​ ​ ​ $ (68) ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (32,291) ​ ​ ​ ​ $ 3,494 ​ ​ ​ ​ $ (146,762) ​ ​ ​ ​ $ (175,627) ​ ​ ​ ​ $ (6,389) ​ ​ ​ ​ $ (182,016) ​ ​
Balance as of December 31, 2022
​ ​ ​ ​ ​ ​ $ 11,503 ​ ​ ​ ​ $ 1,052,959 ​ ​ ​ ​ $ (100,828) ​ ​ ​ ​ $ 17,650 ​ ​ ​ ​ $ (1,133,972) ​ ​ ​ ​ $ (152,688) ​ ​ ​ ​ $ 14,964 ​ ​ ​ ​ $ (137,724) ​ ​
The notes are an integral part of the Consolidated Financial Statements.
F-7
 
Consolidated Statement of Cash Flows
(Amounts in thousands, except per share and per unit data)
​ ​ ​ ​ ​ ​
Year Ended
​
​ ​ ​
Notes
​ ​
December 31, 2022
​ ​
December 31, 2021
​ ​
December 31, 2020
​
Cash flows from operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Income (loss) after taxation
​ ​ ​ ​ ​ ​ $ (620,598) ​ ​ ​ ​ $ (325,206) ​ ​ ​ ​ $ (23,474) ​ ​
Cash flows from operations reconciliation: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Depreciation, depletion and amortization
​ ​
7
​ ​ ​ ​ 222,257 ​ ​ ​ ​ ​ 167,644 ​ ​ ​ ​ ​ 117,290 ​ ​
Accretion of asset retirement obligations
​ ​
19
​ ​ ​ ​ 27,569 ​ ​ ​ ​ ​ 24,396 ​ ​ ​ ​ ​ 15,424 ​ ​
Income tax (benefit) expense
​ ​
8
​ ​ ​ ​ (178,904) ​ ​ ​ ​ ​ (225,694) ​ ​ ​ ​ ​ (113,266) ​ ​
(Gain) loss on fair value adjustments of unsettled financial instruments
​ ​
13
​ ​ ​ ​ 861,457 ​ ​ ​ ​ ​ 652,465 ​ ​ ​ ​ ​ 238,795 ​ ​
Asset retirement costs
​ ​
19
​ ​ ​ ​ (4,889) ​ ​ ​ ​ ​ (2,879) ​ ​ ​ ​ ​ (2,442) ​ ​
(Gain) loss on natural gas and oil properties and equipment
​ ​
5,10,11
​ ​ ​ ​ (2,379) ​ ​ ​ ​ ​ 901 ​ ​ ​ ​ ​ 1,356 ​ ​
Gain on bargain purchases
​ ​
5
​ ​ ​ ​ (4,447) ​ ​ ​ ​ ​ (58,072) ​ ​ ​ ​ ​ (17,172) ​ ​
Finance costs
​ ​
21
​ ​ ​ ​ 100,799 ​ ​ ​ ​ ​ 50,628 ​ ​ ​ ​ ​ 43,327 ​ ​
Revaluation of contingent consideration
​ ​
24
​ ​ ​ ​ — ​ ​ ​ ​ ​ 8,963 ​ ​ ​ ​ ​ 567 ​ ​
Hedge modifications
​ ​
13
​ ​ ​ ​ (133,573) ​ ​ ​ ​ ​ (10,164) ​ ​ ​ ​ ​ (7,723) ​ ​
Non-cash equity compensation
​ ​
7,17
​ ​ ​ ​ 8,051 ​ ​ ​ ​ ​ 7,400 ​ ​ ​ ​ ​ 5,007 ​ ​
Working capital adjustments: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Change in trade receivables and other current assets
​ ​ ​ ​ ​ ​ ​ 13,760 ​ ​ ​ ​ ​ (126,957) ​ ​ ​ ​ ​ 4,348 ​ ​
Change in other non-current assets
​ ​ ​ ​ ​ ​ ​ (580) ​ ​ ​ ​ ​ (556) ​ ​ ​ ​ ​ (1,173) ​ ​
Change in trade and other payables and other current
liabilities
​ ​ ​ ​ ​ ​ ​ 132,349 ​ ​ ​ ​ ​ 162,486 ​ ​ ​ ​ ​ (12,174) ​ ​
Change in other non-current liabilities
​ ​ ​ ​ ​ ​ ​ (6,794) ​ ​ ​ ​ ​ 5,707 ​ ​ ​ ​ ​ (1,130) ​ ​
Cash generated from operations
​ ​ ​ ​ ​ ​ $ 414,078 ​ ​ ​ ​ $ 331,062 ​ ​ ​ ​ $ 247,560 ​ ​
Cash paid for income taxes
​ ​ ​ ​ ​ ​ ​ (26,314) ​ ​ ​ ​ ​ (10,880) ​ ​ ​ ​ ​ (5,850) ​ ​
Net cash provided by operating activities
​ ​ ​ ​ ​ ​ $ 387,764 ​ ​ ​ ​ $ 320,182 ​ ​ ​ ​ $ 241,710 ​ ​
Cash flows from investing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Consideration for business acquisitions, net of cash acquired
​ ​
5
​ ​ ​ $ (24,088) ​ ​ ​ ​ $ (286,804) ​ ​ ​ ​ $ (100,138) ​ ​
Consideration for asset acquisitions
​ ​
5
​ ​ ​ ​ (264,672) ​ ​ ​ ​ ​ (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, 13
​ ​ ​ ​ — ​ ​ ​ ​ ​ (56,466) ​ ​ ​ ​ ​ — ​ ​
Expenditures on natural gas and oil properties and equipment
​ ​
10,11
​ ​ ​ ​ (86,079) ​ ​ ​ ​ ​ (50,175) ​ ​ ​ ​ ​ (21,947) ​ ​
Proceeds on disposals of natural gas and oil properties and equipment
​ ​
10,11
​ ​ ​ ​ 12,189 ​ ​ ​ ​ ​ 2,663 ​ ​ ​ ​ ​ 3,712 ​ ​
Other acquired intangibles
​ ​
13
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (2,900) ​ ​
Contingent consideration payments
​ ​
24
​ ​ ​ ​ (23,807) ​ ​ ​ ​ ​ (10,822) ​ ​ ​ ​ ​ (893) ​ ​
Net cash used in investing activities
​ ​ ​ ​ ​ ​ $ (386,457) ​ ​ ​ ​ $ (627,712) ​ ​ ​ ​ $ (245,119) ​ ​
Cash flows from financing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Repayment of borrowings
​ ​
21
​ ​ ​ $ (2,139,686) ​ ​ ​ ​ $ (1,432,566) ​ ​ ​ ​ $ (705,314) ​ ​
Proceeds from borrowings
​ ​
21
​ ​ ​ ​ 2,587,554 ​ ​ ​ ​ ​ 1,727,745 ​ ​ ​ ​ ​ 799,650 ​ ​
Cash paid for interest
​ ​
21
​ ​ ​ ​ (82,936) ​ ​ ​ ​ ​ (41,623) ​ ​ ​ ​ ​ (34,335) ​ ​
Debt issuance cost
​ ​
21
​ ​ ​ ​ (34,234) ​ ​ ​ ​ ​ (10,255) ​ ​ ​ ​ ​ (7,799) ​ ​
(Increase) decrease in restricted cash
​ ​
3
​ ​ ​ ​ (36,287) ​ ​ ​ ​ ​ 1,838 ​ ​ ​ ​ ​ (12,637) ​ ​
Hedge modifications associated with ABS Notes
​ ​
13,21
​ ​ ​ ​ (105,316) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Proceeds from equity issuance, net
​ ​
16
​ ​ ​ ​ — ​ ​ ​ ​ ​ 213,844 ​ ​ ​ ​ ​ 81,407 ​ ​
Principal element of lease payments
​ ​
20
​ ​ ​ ​ (11,233) ​ ​ ​ ​ ​ (8,606) ​ ​ ​ ​ ​ (3,684) ​ ​
Cancellation (settlement) of warrants, net
​ ​
16
​ ​ ​ ​ 137 ​ ​ ​ ​ ​ (1,429) ​ ​ ​ ​ ​ — ​ ​
Dividends to shareholders
​ ​
18
​ ​ ​ ​ (143,455) ​ ​ ​ ​ ​ (130,239) ​ ​ ​ ​ ​ (98,527) ​ ​
Distributions to non-controlling interest owners
​ ​ ​ ​ ​ ​ ​ (6,389) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares by the EBT
​ ​
16
​ ​ ​ ​ (22,931) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares
​ ​
16
​ ​ ​ ​ (11,760) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (15,634) ​ ​
Net cash provided by financing activities
​ ​ ​ ​ ​ ​ $ (6,536) ​ ​ ​ ​ $ 318,709 ​ ​ ​ ​ $ 3,127 ​ ​
Net change in cash and cash equivalents
​ ​ ​ ​ ​ ​ ​ (5,229) ​ ​ ​ ​ ​ 11,179 ​ ​ ​ ​ ​ (282) ​ ​
Cash and cash equivalents, beginning of period
​ ​ ​ ​ ​ ​ ​ 12,558 ​ ​ ​ ​ ​ 1,379 ​ ​ ​ ​ ​ 1,661 ​ ​
Cash and cash equivalents, end of period
​ ​ ​ ​ ​ ​ $ 7,329 ​ ​ ​ ​ $ 12,558 ​ ​ ​ ​ $ 1,379 ​ ​
The notes are an integral part of the Consolidated Financial Statements.
F-8
 
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
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F-9
 
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 U.S. onshore upstream and midstream assets. The Company’s assets are located within the Central Region and Appalachian Basin of the U.S.
The Company 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 Phoenix House, 1 Station Hill, Reading, Berkshire, RG1 1NB, 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 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 U.S. 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 U.S. 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
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,
 
F-10
 
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.
In accordance with IFRS the Company establishes segments on the basis those components of the Company are evaluated regularly by the chief executive officer, DEC’s chief operating decision maker, when deciding how to allocate resources and in assessing performance. When evaluating performance as well as when acquiring and managing assets the chief operating decision maker does so in a consolidated and complementary fashion to vertically integrate and improve margins. 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 U.S.
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 12 months from the date of approval of 2022 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 for the assessment period, which represents approximately 85%, 75%, and 70% of total production volumes hedged for the years ending December 31, 2023, 2024 and 2025 respectively;
​
•
The scenario also includes the scheduled principal and interest payments on our current debt arrangements and the funding of a dividend utilizing Free Cash Flow; and
​
•
The continuation of capital expenditures directed at our emissions reductions initiatives.
​
The Directors and Senior Leadership also consider various scenarios around the Base Plan that primarily reflect a more severe, but plausible, downside impact of the principal risks, both individually and in the aggregate, as well as the additional capital requirements that downside scenarios could place on us.
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%.
Scenario 3: A market or regulatory event (e.g. climate change legislation) triggers an increase in operating and midstream expenses by approximately 5%.
 
F-11
 
Under these downside sensitivity scenarios, the Company remains cash flow positive. The Company meets its working capital requirements, which 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 2022, 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 U.S., 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.
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 12 months from the date of approval of these Consolidated Financial Statements.
Prior Period Reclassifications and Changes in Presentation
Reclassifications in the Consolidated Statement of Financial Position and Consolidated Statement of Changes in Equity
To provide additional transparency into equity activity, the Company has reclassified certain amounts in its prior year Consolidated Statement of Financial Position and Consolidated Statement of Changes in Equity to conform to its current period presentation. These changes in reclassification do not affect total comprehensive income previously reported in the Consolidated Statement of Changes in Equity.
The Company reclassified $68,537 in “Repurchase of shares” from “Retained Earnings (Accumulated Deficit)” to “Treasury Reserve” in the accompanying 2021 Consolidated Statement of Financial Position and Consolidated Statement of Changes in Equity. The Company reclassified $52,903 in “Repurchase of shares” from “Retained Earnings (Accumulated Deficit)” to “Treasury Reserve” in the accompanying 2020 Consolidated Statement of Changes in Equity.
Reclassifications in the Consolidated Statement of Cash Flows
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 in the Consolidated Statement of Cash Flows.
The Company reclassified $4,233 and $1,958 in “Change in other current assets” to “Change in trade receivables and other current assets” and $153,179 and $7,402 in “Change in other current and non-current liabilities” to “Change in trade and other payables and other current liabilities” in the accompanying 2021 and 2020 Consolidated Statement of Cash Flows, respectively. The Company also reclassified $1,838 and $12,637 in “(Increase) decrease in restricted cash” from “Cash flows from investing activities” to “Cash flows from financing activities” in the accompanying 2021 and 2020 Consolidated Statement of Cash Flows, respectively.
 
F-12
 
Basis of Consolidation
The Consolidated Financial Statements for the year ended December 31, 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 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
​
>
Sooner State Joint ABS Holdings LLC(a)
​
>
Diversified ABS Phase VI Holdings LLC
​
>
Diversified ABS Phase VI LLC
​
>
Diversified ABS VI Upstream LLC
​
>
OCM Denali ABS VI Upstream LLC
​
>
DP RBL Co LLC
​
>
BlueStone Natural Resources II LLC
​
>
DP Legacy Central LLC
​
>
Diversified Energy Marketing LLC
​
>
DP Tapstone Energy Holdings LLC
​
>
DP Legacy Tapstone LLC
​
>
Giant Land, LLC(b)
​
>
Link Land LLC(b)
​
>
Old Faithful Land LLC(b)
​
>
Riverside Land LLC(b)
​
>
Splendid Land LLC(b)
​
>
Chesapeake Granite Wash Trust(c)
​
>
TGG Cotton Valley Assets, 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
​
>
DGOC Holdings Sub III LLC
​
>
Diversified Energy Group LLC
​
>
Diversified Energy Company LLC
​
>
Next LVL Energy, LLC
​
​
​
(a)
Owned 51.25% by Diversified Energy Company PLC.
​
(b)
Owned 55% by Diversified Energy Company PLC.
​
(c)
Diversified Production, LLC holds 50.8% of the issued and outstanding common shares of Chesapeake Granite Wash Trust.
​
NOTE 3 — SIGNIFICANT ACCOUNTING POLICIES
The preparation of the Consolidated Financial Statements in compliance with UK-adopted international accounting standards 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
 
F-13
 
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.
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 identified over a three (3) year term. The Oaktree Funding Commitment provided 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 fund 50% of the net purchase price in exchange for proportionate working interests of 51.25% and 48.75% during Tranche I deals, or joint acquisitions made during the first 18 months of the agreement, and 52.5% and 47.5% during Tranche II deals, or joint acquisitions made during the second 18 months of the agreement, respectively. The Company’s greater share reflects the upfront promote it will receive from Oaktree 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% unlevered internal rate of return, Oaktree will convey a back-end promote to the Company which will increase the Company’s working interest to 59.625% for both Tranche I and Tranche II deals. 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.
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 U.S. 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, 2022 and 2021, the Company’s cash balance was $7,329 and $12,558, 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 dispersed 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, 2022 and 2021, the Company considered
 
F-14
 
a portion of these working interest receivables uncollectable and recorded an allowance for credit losses in the amount of $8,941 and $6,141, respectively. Refer to 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 settlements 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 securitizations discussed in Note 21. These reserves approximate six to seven months of interest, depending on the Note, as well as 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.
 
F-15
 
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​
Cash restricted by asset-backed securitizations
​ ​ ​ $ 54,552 ​ ​ ​ ​ $ 18,069 ​ ​
Other restricted cash
​ ​ ​ ​ 836 ​ ​ ​ ​ ​ 1,033 ​ ​
Total restricted cash
​ ​ ​ $ 55,388 ​ ​ ​ ​ $ 19,102 ​ ​
Classified as: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Current asset
​ ​ ​ $ 7,891 ​ ​ ​ ​ $ 1,033 ​ ​
Non-current asset
​ ​ ​ ​ 47,497 ​ ​ ​ ​ ​ 18,069 ​ ​
Total ​ ​ ​ $ 55,388 ​ ​ ​ ​ $ 19,102 ​ ​
Natural Gas and Oil Properties
Natural gas and oil activities are accounted for using the principles of the successful efforts method of accounting as described below.
Development and Acquisition Costs
Costs incurred to purchase, lease, or otherwise acquire a property are capitalized when incurred. 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.
Depletion
Proved natural gas, oil and NGL reserve volumes are used as the basis to calculate unit-of-production depletion rates. Leasehold costs are depleted on the unit-of-production basis over the total proved reserves of the relevant area while production and development wells are depleted over proved producing reserves.
Intangible Assets
Software Development
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 cost incurred by third parties, 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
 
F-16
 
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.
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(a)
​ ​
3
​
​
(a)
Represents intangible assets acquired in business combinations and asset acquisitions.
​
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 the 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
 
F-17
 
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 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, 2022 and 2021, the Company had no midstream asset retirement obligations.
Taxation
Deferred Taxation
Deferred tax assets and liabilities arise from temporary differences 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.
Current Taxation
Current income tax assets and liabilities for the years ended December 31, 2022 and 2021 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
 
F-18
 
the most likely amount, or the expected value, depending on which method provides a better prediction of the resolution of the uncertainty.
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 the 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 interests is included as a liability, described 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.
Asset Retirement Revenue
Revenue from third-party asset retirement services 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.
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, 2022 and 2021, the Company had three types of share-based payment awards: RSUs, PSUs and Options. The fair value of the Company’s RSUs is measured using the stock
 
F-19
 
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;
​
•
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, 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 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, the “concentration test”. 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, gain on bargain purchases 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
 
F-20
 
than through the Consolidated Statement of Comprehensive Income. More information regarding conclusions reached with respect to this judgment is included in Note 5.
The determination and allocation of fair values to the identifiable assets acquired and liabilities assumed are based on various market participant 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 combinations 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, 2022, 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, 2022, 2021 and 2020. Please refer to Note 10 for additional information.
 
F-21
 
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 Volume Estimates
Proved reserves are the estimated volumes of natural gas, oil and NGLs that can be economically produced with reasonable certainty from known reservoirs under existing economic conditions and operating methods.
In estimating proved natural gas and oil reserves, we rely on interpretations and judgment of available geological, geophysical, engineering and production data as well as the use of certain economic assumptions such as commodity pricing. Additional assumptions include operating expenses, capital expenditures and taxes. Many of the factors, assumptions and variables involved in estimating proved reserves are subject to change over time and therefore affect the estimates of natural gas, oil and NGL reserve volumes.
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 retire 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. See 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.
2022 Acquisitions
ConocoPhillips Asset Acquisition
On September 27, 2022 the Company acquired certain upstream assets and related facilities within the Central Region from ConocoPhillips. Given the concentration of assets, this transaction was considered an
 
F-22
 
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 $209,766, including customary purchase price adjustments. Transaction costs associated with the acquisition were negligible. The Company funded the purchase with available cash on hand and a draw on the Credit Facility. In the period from its acquisition to December 31, 2022 the ConocoPhillips assets increased the Company’s revenue by $25,217.
The provisional assets and liabilities assumed were as follows:
​ Consideration paid ​ ​ ​ ​ ​ ​ ​
​
Cash consideration
​ ​ ​ $ 209,766 ​ ​
​
Total consideration
​ ​ ​ $ 209,766 ​ ​
​ Net assets acquired ​ ​ ​ ​ ​ ​ ​
​
Natural gas and oil properties
​ ​ ​ $ 210,227 ​ ​
​
Asset retirement obligations, asset portion
​ ​ ​ ​ 17,380 ​ ​
​
Property, plant and equipment
​ ​ ​ ​ 302 ​ ​
​
Other current assets
​ ​ ​ ​ 98 ​ ​
​
Asset retirement obligations, liability portion
​ ​ ​ ​ (17,380) ​ ​
​
Other current liabilities
​ ​ ​ ​ (861) ​ ​
​
Net assets acquired
​ ​ ​ $ 209,766 ​ ​
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 $47,468, 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 December 31, 2022 the East Texas assets increased the Company’s revenue by $34,833.
The provisional assets and liabilities assumed were as follows:
​ Consideration paid ​ ​ ​ ​ ​ ​ ​
​
Cash consideration
​ ​ ​ $ 47,468 ​ ​
​
Total consideration
​ ​ ​ $ 47,468 ​ ​
​ Net assets acquired ​ ​ ​ ​ ​ ​ ​
​
Natural gas and oil properties
​ ​ ​ $ 50,590 ​ ​
​
Asset retirement obligations, asset portion
​ ​ ​ ​ 7,015 ​ ​
​
Property, plant and equipment
​ ​ ​ ​ 1,049 ​ ​
​
Trade receivables, net
​ ​ ​ ​ 23 ​ ​
​
Asset retirement obligations, liability portion
​ ​ ​ ​ (7,015) ​ ​
​
Other non-current liabilities
​ ​ ​ ​ (1,667) ​ ​
​
Other current liabilities
​ ​ ​ ​ (2,527) ​ ​
​
Net assets acquired
​ ​ ​ $ 47,468 ​ ​
Other Acquisitions
During the period ended December 31, 2022 the Company acquired three asset retirement companies for an aggregate consideration of $13,949, inclusive of customary purchase price adjustments. The Company
 
F-23
 
will also pay an additional $3,150 in deferred consideration through November 2024. When evaluating these transactions, the Company determined they did not have significant asset concentrations and as a result it had acquired identifiable sets of inputs, processes and outputs and concluded the transactions were business combinations. This expansion in the Company’s internal asset retirement operations brings the total plugging rigs owned and operated by the Company to 15 as of December 31, 2022.
On April 1, 2022 the Company acquired certain midstream assets, inclusive of a processing facility, in the Central Region that are contiguous to its existing East Texas assets. The Company paid purchase consideration of $10,139, inclusive of customary purchase price adjustments and transaction costs. When evaluating the transaction, the Company 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 provisional fair value of the net assets acquired was $10,742 generating a bargain purchase gain of $603.
On November 21, 2022 the Company acquired certain midstream assets in the Central Region that are contiguous to its existing East Texas assets. The Company paid purchase consideration of $7,438, inclusive of customary purchase price adjustments and transaction costs. Given the concentration of assets, this transaction was considered an asset acquisition rather than a business combination.
Transaction costs associated with the other acquisitions noted above were insignificant and the Company funded the aggregate cash consideration with existing cash on hand.
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 five wells which remained under development as of December 31, 2021 and have now been completed by the Company. The Company will serve as the sole operator of the assets. When evaluating the transaction, the Company 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. During 2022, the Company recorded $3,853 in measurement period adjustments as purchase accounting was finalized. These adjustments were recorded as an increase in the bargain purchase gain associated with the transaction. Transaction costs associated with the acquisition were $4,039 and were 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, 2022. The remaining amounts in the Company’s Consolidated Statement of Financial Position associated with non-controlling interest are immaterial and working capital in nature.
 
F-24
 
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, the Company 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 were expensed. DEC funded the purchase with proceeds from a drawdown on the Credit Facility. During 2022 purchase accounting was finalized and no measurement period adjustments were recorded.
As part of the acquisition, the Company obtained the option to novate or extinguish the Tanos hedge book. In conjunction with the closing settlement, the Company 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.
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 were 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. During 2022 purchase accounting was finalized and no measurement period adjustments were recorded.
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 were 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. During 2022 purchase accounting was finalized and no measurement period adjustments were recorded.
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.
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
 
F-25
 
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.
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, the Indigo, Blackbeard, Tanos and Tapstone acquisitions each had occurred on January 1, 2021, and the East Texas Assets and ConocoPhillips acquisition each had occurred on January 1, 2022.
​ ​ ​
Year Ended
​
​ ​ ​
December 31, 2022
​ ​
December 31, 2021
​ ​
December 31, 2020
​
Revenues
​ ​ ​ $ 2,010,927 ​ ​ ​ ​ $ 1,249,983 ​ ​ ​ ​ $ 440,142 ​ ​
Net income (loss)
​ ​ ​ $ (594,097) ​ ​ ​ ​ $ (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, the Indigo, Blackbeard, Tanos and Tapstone acquisitions each been completed at January 1, 2021, and the East Texas Assets and ConocoPhillips acquisitions each been completed at January 1, 2022, 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, Tapstone, East Texas Assets and ConocoPhillips, 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
On February 8, 2023 the Company announced it entered a conditional agreement to acquire certain upstream assets and related infrastructure in the Central Region from Tanos Energy Holdings II LLC (“Tanos II”). The transaction subsequently closed on March 1, 2023 for a total purchase consideration of $250,000 before customary purchase price adjustments. The transaction was funded with proceeds from the February 2023 equity raise, cash on hand and existing availability on the Credit Facility for which the borrowing base was upsized concurrent to the closing of the Tanos II transaction. Refer to Notes 16 and 21 for additional information regarding the Company’s share capital and borrowings.
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 as well as asset retirement and other services to third parties. All revenue was generated in the U.S.
 
F-26
 
The following table reconciles the Company’s revenue for the periods presented:
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Natural gas
​ ​ ​ $ 1,544,658 ​ ​ ​ ​ $ 818,726 ​ ​ ​ ​ $ 343,425 ​ ​
NGLs
​ ​ ​ ​ 188,733 ​ ​ ​ ​ ​ 115,747 ​ ​ ​ ​ ​ 23,173 ​ ​
Oil
​ ​ ​ ​ 139,620 ​ ​ ​ ​ ​ 38,634 ​ ​ ​ ​ ​ 15,064 ​ ​
Total commodity revenue
​ ​ ​ $ 1,873,011 ​ ​ ​ ​ $ 973,107 ​ ​ ​ ​ $ 381,662 ​ ​
Midstream
​ ​ ​ ​ 32,798 ​ ​ ​ ​ ​ 31,988 ​ ​ ​ ​ ​ 25,389 ​ ​
Other(a)
​ ​ ​ ​ 13,540 ​ ​ ​ ​ ​ 2,466 ​ ​ ​ ​ ​ 1,642 ​ ​
Total revenue
​ ​ ​ $ 1,919,349 ​ ​ ​ ​ $ 1,007,561 ​ ​ ​ ​ $ 408,693 ​ ​
​
(a)
Includes asset retirement and other revenue. Refer to Note 3 for additional information.
​
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, 2022, no customers individually comprised more than 10% of total revenues. During the year ended December 31, 2021, two customers individually comprised more than 10% of total revenues, representing 22% of consolidated revenues. During the year ended December 31, 2020, two customers individually comprised more than 10% of total revenues, representing 22% of consolidated revenues.
NOTE 7 — EXPENSES BY NATURE
The following table provides a detail of the Company’s expenses for the periods presented:
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
LOE(a)
​ ​ ​ $ 182,817 ​ ​ ​ ​ $ 119,594 ​ ​ ​ ​ $ 92,288 ​ ​
Production taxes(b)
​ ​ ​ ​ 73,849 ​ ​ ​ ​ ​ 30,518 ​ ​ ​ ​ ​ 13,705 ​ ​
Midstream operating expense(c)
​ ​ ​ ​ 71,154 ​ ​ ​ ​ ​ 60,481 ​ ​ ​ ​ ​ 52,815 ​ ​
Transportation expense(d)
​ ​ ​ ​ 118,073 ​ ​ ​ ​ ​ 80,620 ​ ​ ​ ​ ​ 45,155 ​ ​
Total operating expense
​ ​ ​ $ 445,893 ​ ​ ​ ​ $ 291,213 ​ ​ ​ ​ $ 203,963 ​ ​
Depreciation and amortization
​ ​ ​ ​ 51,877 ​ ​ ​ ​ ​ 44,841 ​ ​ ​ ​ ​ 33,673 ​ ​
Depletion
​ ​ ​ ​ 170,380 ​ ​ ​ ​ ​ 122,803 ​ ​ ​ ​ ​ 83,617 ​ ​
Total depreciation, depletion and amortization
​ ​ ​ $ 222,257 ​ ​ ​ ​ $ 167,644 ​ ​ ​ ​ $ 117,290 ​ ​
Employees, administrative costs and professional services(e)
​ ​ ​ ​ 77,172 ​ ​ ​ ​ ​ 56,812 ​ ​ ​ ​ ​ 47,181 ​ ​
Costs associated with acquisitions(f)
​ ​ ​ ​ 15,545 ​ ​ ​ ​ ​ 27,743 ​ ​ ​ ​ ​ 10,465 ​ ​
Other adjusting costs(g)
​ ​ ​ ​ 69,967 ​ ​ ​ ​ ​ 10,371 ​ ​ ​ ​ ​ 14,581 ​ ​
Non-cash equity compensation(h)
​ ​ ​ ​ 8,051 ​ ​ ​ ​ ​ 7,400 ​ ​ ​ ​ ​ 5,007 ​ ​
Total G&A
​ ​ ​ $ 170,735 ​ ​ ​ ​ $ 102,326 ​ ​ ​ ​ $ 77,234 ​ ​
Non-recurring allowance for credit losses
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 6,931 ​ ​
Recurring allowance for credit losses(i)
​ ​ ​ ​ — ​ ​ ​ ​ ​ (4,265) ​ ​ ​ ​ ​ 1,559 ​ ​
Total expense
​ ​ ​ $ 838,885 ​ ​ ​ ​ $ 556,918 ​ ​ ​ ​ $ 406,977 ​ ​
Aggregate remuneration (including Directors):
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Wages and salaries
​ ​ ​ $ 113,267 ​ ​ ​ ​ $ 83,790 ​ ​ ​ ​ $ 75,719 ​ ​
Payroll taxes
​ ​ ​ ​ 9,516 ​ ​ ​ ​ ​ 7,137 ​ ​ ​ ​ ​ 5,383 ​ ​
Benefits
​ ​ ​ ​ 23,828 ​ ​ ​ ​ ​ 19,083 ​ ​ ​ ​ ​ 14,926 ​ ​
Total employees and benefits expense
​ ​ ​ $ 146,611 ​ ​ ​ ​ $ 110,010 ​ ​ ​ ​ $ 96,028 ​ ​
 
F-27
 
​
(a)
LOE includes costs incurred to maintain producing properties. Such costs include direct and contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.
​
(b)
Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural gas, NGLs and oil production at fixed rates established by federal, state or local taxing authorities. Property taxes are generally based on the taxing jurisdictions’ valuation of the 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)
Employees, administrative costs and professional services includes payroll and benefits for our administrative and corporate staff, costs of maintaining administrative and corporate offices, costs of managing our production operations, franchise taxes, public company costs, fees for audit and other professional services and legal compliance.
​
(f)
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 the Company pays 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, these costs include costs related to integrating IT systems and consulting as well as internal workforce costs directly related to integrating acquisitions into the Company’s system.
​
(g)
Other adjusting costs for the year ended December 31, 2022 primarily consisted of $28,345 in contract terminations which will allow the Company to obtain more favorable pricing in the future and $31,099 in costs associated with deal breakage and/or sourcing costs for acquisitions. For the year ended December 31, 2021, other adjusting costs were primarily associated with one-time projects and contemplated transactions. Also included are expenses associated with an unused firm transportation agreement acquired as part of the Carbon Acquisition. For the year ended December 31, 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.
​
(h)
Non-cash equity compensation reflects the expense recognition related to share-based compensation provided to certain key members of the management team. Refer to Note 17 for additional information regarding non-cash share-based compensation.
​
(i)
Allowance for credit losses consists of the recognition and reversal of credit losses. Refer to Note 14 for additional information regarding credit losses.
​
The number of employees was as follows for the years presented:
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Number of production support employees, including
Directors
​ ​ ​ ​ 362 ​ ​ ​ ​ ​ 283 ​ ​ ​ ​ ​ 183 ​ ​
Number of production employees
​ ​ ​ ​ 1,220 ​ ​ ​ ​ ​ 1,143 ​ ​ ​ ​ ​ 924 ​ ​
Workforce ​ ​ ​ ​ 1,582 ​ ​ ​ ​ ​ 1,426 ​ ​ ​ ​ ​ 1,107 ​ ​
 
F-28
 
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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Executive Directors ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Salary
​ ​ ​ $ 1,157 ​ ​ ​ ​ $ 1,119 ​ ​ ​ ​ $ 1,090 ​ ​
Taxable benefits(a)
​ ​ ​ ​ 24 ​ ​ ​ ​ ​ 22 ​ ​ ​ ​ ​ 16 ​ ​
Benefit plan(b)
​ ​ ​ ​ 73 ​ ​ ​ ​ ​ 71 ​ ​ ​ ​ ​ 71 ​ ​
Bonus(c)
​ ​ ​ ​ 1,631 ​ ​ ​ ​ ​ 1,427 ​ ​ ​ ​ ​ 1,537 ​ ​
Long-term incentives(c)
​ ​ ​ ​ 3,193 ​ ​ ​ ​ ​ 3,018 ​ ​ ​ ​ ​ 938 ​ ​
Total Executive Directors’ remuneration
​ ​ ​ $ 6,078 ​ ​ ​ ​ $ 5,657 ​ ​ ​ ​ $ 3,652 ​ ​
Non-Executive Directors ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Fees
​ ​ ​ $ 911 ​ ​ ​ ​ $ 683 ​ ​ ​ ​ $ 763 ​ ​
Total Non-Executive Directors’ remuneration
​ ​ ​ $ 911 ​ ​ ​ ​ $ 683 ​ ​ ​ ​ $ 763 ​ ​
Total remuneration
​ ​ ​ $ 6,989 ​ ​ ​ ​ $ 6,340 ​ ​ ​ ​ $ 4,415 ​ ​
​
(a)
Taxable benefits were comprised of Company paid life insurance premiums and automobile reimbursements.
​
(b)
Reflects matching contributions under the Company’s 401(k) plan.
​
(c)
Further details of the bonus outcome for 2022 and long-term incentives can be found in the Company’s 2022 Annual Report.
​
Auditors’ remuneration for the Company was as follows for the periods presented:
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
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
​ ​ ​ $ 1,790 ​ ​ ​ ​ $ 1,694 ​ ​ ​ ​ $ 1,196 ​ ​
Audit-related assurance services(a)
​ ​ ​ ​ 774 ​ ​ ​ ​ ​ 1,628 ​ ​ ​ ​ ​ 1,146 ​ ​
Other assurance services
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 87 ​ ​
Total auditors’ remuneration (PwC)
​ ​ ​ $ 2,564 ​ ​ ​ ​ $ 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.
​
NOTE 8 — TAXATION
The Company files a consolidated U.S. federal tax return, multiple state tax returns, and a separate UK tax return for the Parent entity. The consolidated taxable income includes an allocable 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, 2022, 2021 and 2020, the Company had a tax benefit of $178,904, $225,694 and $113,266, respectively. The effective tax rate used for the year ended December 31, 2022 was 22.4%, compared to 41.0% for the year ended December 31, 2021 and 82.8% for the year ended
 
F-29
 
December 31, 2020. The December 31, 2022 effective tax rate was primarily impacted by changes in state taxes as a result of acquisitions. The December 31, 2021 and 2020 effective tax rate was primarily impacted by the Company’s recognition of the U.S. marginal well tax credit available to qualified producers in 2021 and 2020, 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 U.S. 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 U.S. 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 was not available for tax year 2022 due to improved commodity prices.
The provision for income taxes in the Consolidated Statement of Comprehensive Income is summarized below:
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Current income tax expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Federal
​ ​ ​ $ (513) ​ ​ ​ ​ $ 25,738 ​ ​ ​ ​ $ 233 ​ ​
State
​ ​ ​ ​ 2,841 ​ ​ ​ ​ ​ 11,958 ​ ​ ​ ​ ​ 4,923 ​ ​
Foreign – UK
​ ​ ​ ​ 107 ​ ​ ​ ​ ​ (52) ​ ​ ​ ​ ​ 616 ​ ​
Total current income tax expense
​ ​ ​ $ 2,435 ​ ​ ​ ​ $ 37,644 ​ ​ ​ ​ $ 5,772 ​ ​
Deferred income tax (benefit) expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Federal
​ ​ ​ $ (169,531) ​ ​ ​ ​ $ (233,679) ​ ​ ​ ​ $ (108,627) ​ ​
State
​ ​ ​ ​ (11,863) ​ ​ ​ ​ ​ (29,597) ​ ​ ​ ​ ​ (10,411) ​ ​
Foreign – UK
​ ​ ​ ​ 55 ​ ​ ​ ​ ​ (62) ​ ​ ​ ​ ​ — ​ ​
Total deferred income tax (benefit) expense
​ ​ ​ $ (181,339) ​ ​ ​ ​ $ (263,338) ​ ​ ​ ​ $ (119,038) ​ ​
Total income tax (benefit) expense
​ ​ ​ $ (178,904) ​ ​ ​ ​ $ (225,694) ​ ​ ​ ​ $ (113,266) ​ ​
The effective tax rates and differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Income (loss) before taxation
​ ​ ​ $ (799,502) ​ ​ ​ ​ $ (550,900) ​ ​ ​ ​ $ (136,740) ​ ​
Income tax benefit (expense)
​ ​ ​ ​ 178,904 ​ ​ ​ ​ ​ 225,694 ​ ​ ​ ​ ​ 113,266 ​ ​
Effective tax rate
​ ​ ​ ​ 22.4% ​ ​ ​ ​ ​ 41.0% ​ ​ ​ ​ ​ 82.8% ​ ​
​ ​ ​
Year Ended
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Expected tax at statutory U.S. federal income tax rate
​ ​ ​ ​ 21.0% ​ ​ ​ ​ ​ 21.0% ​ ​ ​ ​ ​ 21.0% ​ ​
State income taxes, net of federal tax benefit
​ ​ ​ ​ 1.2% ​ ​ ​ ​ ​ 4.4% ​ ​ ​ ​ ​ 5.4% ​ ​
Federal credits
​ ​ ​ ​ —% ​ ​ ​ ​ ​ 15.4% ​ ​ ​ ​ ​ 58.8% ​ ​
Other, net
​ ​ ​ ​ 0.2% ​ ​ ​ ​ ​ 0.2% ​ ​ ​ ​ ​ (2.4)% ​ ​
Effective tax rate
​ ​ ​ ​ 22.4% ​ ​ ​ ​ ​ 41.0% ​ ​ ​ ​ ​ 82.8% ​ ​
 
F-30
 
The Company had a net deferred tax asset of $358,666 at December 31, 2022 compared to a net deferred tax asset of $176,955 at December 31, 2021. The change was primarily due to an improved commodity price environment generating unrealized losses for unsettled derivatives not recognized for tax purposes. 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.
The following table presents the components of the net deferred income tax asset included in non-current assets and net deferred income tax liability included in non-current liabilities as of the periods presented:
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​
Deferred tax asset
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Asset retirement obligations
​ ​ ​ $ 92,393 ​ ​ ​ ​ $ 114,182 ​ ​
Derivative financial instruments
​ ​ ​ ​ 378,918 ​ ​ ​ ​ ​ 202,802 ​ ​
Allowance for doubtful accounts
​ ​ ​ ​ 2,378 ​ ​ ​ ​ ​ 1,735 ​ ​
Net operating loss carryover
​ ​ ​ ​ 3,865 ​ ​ ​ ​ ​ 562 ​ ​
Federal tax credits carryover
​ ​ ​ ​ 184,975 ​ ​ ​ ​ ​ 183,460 ​ ​
Other
​ ​ ​ ​ 34,507 ​ ​ ​ ​ ​ 13,306 ​ ​
Total deferred tax asset
​ ​ ​ $ 697,036 ​ ​ ​ ​ $ 516,047 ​ ​
Deferred tax liability
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Amortization and depreciation
​ ​ ​ $ (255,440) ​ ​ ​ ​ $ (266,988) ​ ​
Investment in partnerships
​ ​ ​ ​ (82,930) ​ ​ ​ ​ ​ (72,104) ​ ​
Total deferred tax liability
​ ​ ​ $ (338,370) ​ ​ ​ ​ $ (339,092) ​ ​
Net deferred tax asset (liability)
​ ​ ​ $ 358,666 ​ ​ ​ ​ $ 176,955 ​ ​
Balance sheet presentation ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Deferred tax asset
​ ​ ​ $ 371,156 ​ ​ ​ ​ $ 176,955 ​ ​
Deferred tax liability
​ ​ ​ ​ (12,490) ​ ​ ​ ​ ​ — ​ ​
Net deferred tax asset (liability)
​ ​ ​ $ 358,666 ​ ​ ​ ​ $ 176,955 ​ ​
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.
 
F-31
 
The Company reported the effects of deferred tax expense as of and for the year ended December 31, 2022:
​ ​ ​
Opening
Balance
​ ​
Consolidated
Statement of
Comprehensive
Income
​ ​
Other(a)
​ ​
Closing
Balance
​
Asset retirement obligations
​ ​ ​ $ 114,182 ​ ​ ​ ​ $ (21,789) ​ ​ ​ ​ $ — ​ ​ ​ ​ $ 92,393 ​ ​
Allowance for doubtful accounts
​ ​ ​ ​ 1,734 ​ ​ ​ ​ ​ 644 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2,378 ​ ​
Net operating loss carryover
​ ​ ​ ​ 562 ​ ​ ​ ​ ​ 3,360 ​ ​ ​ ​ ​ (57) ​ ​ ​ ​ ​ 3,865 ​ ​
Federal tax credits carryover
​ ​ ​ ​ 183,460 ​ ​ ​ ​ ​ 1,515 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 184,975 ​ ​
Property, plant, and equipment and natural gas and oil properties
​ ​ ​ ​ (266,987) ​ ​ ​ ​ ​ 11,360 ​ ​ ​ ​ ​ 187 ​ ​ ​ ​ ​ (255,440) ​ ​
Derivative financial instruments
​ ​ ​ ​ 202,802 ​ ​ ​ ​ ​ 176,116 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 378,918 ​ ​
Investment in partnerships
​ ​ ​ ​ (72,105) ​ ​ ​ ​ ​ (11,068) ​ ​ ​ ​ ​ 243 ​ ​ ​ ​ ​ (82,930) ​ ​
Other
​ ​ ​ ​ 13,306 ​ ​ ​ ​ ​ 21,201 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 34,507 ​ ​
Total deferred tax asset (liability)
​ ​ ​ $ 176,954 ​ ​ ​ ​ $ 181,339 ​ ​ ​ ​ $ 373 ​ ​ ​ ​ $ 358,666 ​ ​
​
(a)
Amounts primarily relate to deferred taxes acquired as part of acquisition purchase accounting.
​
The Company reported the effects of deferred tax expense as of 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 ​ ​
State net operating loss
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
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’s material deferred tax assets and liabilities all arise in the U.S.
For U.S. 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, 2022, 2021 and 2020, the Company incurred an expense of $107, a benefit of $52, and an expense of $616 in the UK, respectively.
The Company had no uncertain tax position liability at December 31, 2022 or December 31, 2021.
As of December 31, 2022, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $16,837, which $1,629 are subject to limitation. Additionally, the Company had U.S. state NOLs of approximately $7,499, which expire in the years 2034 through 2037.
 
F-32
 
The Company had U.S. marginal well tax credit carryforwards of approximately $184,975 as of December 31, 2022 compared to $183,460 as of December 31, 2021. 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 improved commodity price environment in 2022, the Company did not generate federal tax credits for the year ended December 31, 2022. The tax credits expire in the years 2037 through 2041.
The Company had U.S. federal capital loss carryforwards of $21,401 as of December 31, 2022 compared to $9,904 as of December 31, 2021. For the year ended December 31, 2022, no capital loss carryforwards expired, and the remaining amounts expire in 2023 through 2027. The Company does not expect to utilize the $8,047 carryforwards that expire in 2023, and therefore, a deferred tax asset for these carryforwards has not been recorded.
The Company completed a Section 382 study through December 31, 2022 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 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 16 for additional information regarding the EBT. Basic and diluted earnings (loss) per share are calculated as follows for the periods presented:
​ ​ ​ ​ ​ ​
Year Ended
​
​ ​ ​
Calculation
​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Net income (loss) attributable to Diversified Energy Company PLC
​ ​
A
​ ​ ​
$
(625,410)
​ ​ ​ ​
$
(325,509)
​ ​ ​ ​
$
(23,474)
​ ​
Weighted average shares outstanding – basic and diluted
​ ​
B
​ ​ ​ ​ 844,080 ​ ​ ​ ​ ​ 793,542 ​ ​ ​ ​ ​ 685,170 ​ ​
Earnings (loss) per share – basic and diluted
​ ​
= A/B
​ ​ ​
$
(0.74)
​ ​ ​ ​
$
(0.41)
​ ​ ​ ​
$
(0.03)
​ ​
Due to the Company’s Net loss for the years ended December 31, 2022, 2021 and 2020, 15,334,465,6,492,835 and 3,178,182 potential shares were not included in the computation of diluted EPS because their effect would have been anti-dilutive.
 
F-33
 
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, 2022
​ ​
December 31, 2021
​ ​
December 31, 2020
​
Costs ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Beginning balance
​ ​ ​ $ 2,866,353 ​ ​ ​ ​ $ 1,968,557 ​ ​ ​ ​ $ 1,625,884 ​ ​
Additions(a)
​ ​ ​ ​ 219,490 ​ ​ ​ ​ ​ 1,012,691 ​ ​ ​ ​ ​ 346,385 ​ ​
Disposals(b)
​ ​ ​ ​ (23,380) ​ ​ ​ ​ ​ (114,895) ​ ​ ​ ​ ​ (3,712) ​ ​
Ending balance
​ ​ ​ $ 3,062,463 ​ ​ ​ ​ $ 2,866,353 ​ ​ ​ ​ $ 1,968,557 ​ ​
Depletion and impairment ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Beginning balance
​ ​ ​ $ (336,275) ​ ​ ​ ​ $ (213,472) ​ ​ ​ ​ $ (129,855) ​ ​
Depletion expense
​ ​ ​ ​ (170,380) ​ ​ ​ ​ ​ (122,803) ​ ​ ​ ​ ​ (83,617) ​ ​
Impairment
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Ending balance
​ ​ ​ $ (506,655) ​ ​ ​ ​ $ (336,275) ​ ​ ​ ​ $ (213,472) ​ ​
Net book value
​ ​ ​ $ 2,555,808 ​ ​ ​ ​ $ 2,530,078 ​ ​ ​ ​ $ 1,755,085 ​ ​
​
(a)
For the year ended December 31, 2022, the Company added $285,212 related to acquisitions, offset by $98,802 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 five Tapstone wells that were under development as of December 31, 2021, and seven additional wells the Company participated with a non-operating interest in Appalachia. The remaining change is primarily attributable to recurring capital expenditures. 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)
Disposals for the year ended December 31, 2022 were associated with divestitures of natural gas and oil properties in the normal course of business, none of which were material. For the year ended December 31, 2021, the Company divested $113,752 in natural gas and oil properties related to the Indigo and Tanos undeveloped acreage transactions. For the year ended December 31, 2020 the Company divested 662 wells in McKean, Forest, and Warren Counties, Pennsylvania. Refer to Note 5 for additional information regarding divestitures.
​
Impairment Assessment for Natural Gas and Oil Properties
For the period ended December 31, 2022, the Directors assessed the indicators of impairment, noting volatile pricing in near-term and resilient commodity price on the forward curve after the near-term volatility subsides which supports a healthy 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.
 
F-34
 
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, 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)
​ ​ ​ ​ 9,421 ​ ​ ​ ​ ​ 20,886 ​ ​ ​ ​ ​ 22,399 ​ ​ ​ ​ ​ 34,835 ​ ​ ​ ​ ​ 7,704 ​ ​ ​ ​ ​ 95,245 ​ ​
Disposals
​ ​ ​ ​ (3,423) ​ ​ ​ ​ ​ (9) ​ ​ ​ ​ ​ (1,572) ​ ​ ​ ​ ​ (14) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (5,018) ​ ​
Ending balance(b)
​ ​ ​ $ 47,682 ​ ​ ​ ​ $ 30,369 ​ ​ ​ ​ $ 66,389 ​ ​ ​ ​ $ 433,484 ​ ​ ​ ​ $ 23,743 ​ ​ ​ ​ $ 601,667 ​ ​
Accumulated depreciation ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Beginning balance
​ ​ ​ $ (2,078) ​ ​ ​ ​ $ (4,089) ​ ​ ​ ​ $ (20,186) ​ ​ ​ ​ $ (69,501) ​ ​ ​ ​ $ (1,606) ​ ​ ​ ​ $ (97,460) ​ ​
Period changes
​ ​ ​ ​ (1,819) ​ ​ ​ ​ ​ (3,547) ​ ​ ​ ​ ​ (10,270) ​ ​ ​ ​ ​ (26,330) ​ ​ ​ ​ ​ (947) ​ ​ ​ ​ ​ (42,913) ​ ​
Disposals
​ ​ ​ ​ 290 ​ ​ ​ ​ ​ 9 ​ ​ ​ ​ ​ 1,262 ​ ​ ​ ​ ​ 5 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,566 ​ ​
Ending balance
​ ​ ​ $ (3,607) ​ ​ ​ ​ $ (7,627) ​ ​ ​ ​ $ (29,194) ​ ​ ​ ​ $ (95,826) ​ ​ ​ ​ $ (2,553) ​ ​ ​ ​ $ (138,807) ​ ​
Net book value
​ ​ ​ $ 44,075 ​ ​ ​ ​ $ 22,742 ​ ​ ​ ​ $ 37,195 ​ ​ ​ ​ $ 337,658 ​ ​ ​ ​ $ 21,190 ​ ​ ​ ​ $ 462,860 ​ ​
​ ​ ​
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)
​ ​ ​ ​ 13,494 ​ ​ ​ ​ ​ 2,737 ​ ​ ​ ​ ​ 12,700 ​ ​ ​ ​ ​ 31,485 ​ ​ ​ ​ ​ 10,439 ​ ​ ​ ​ ​ 70,855 ​ ​
Disposals
​ ​ ​ ​ — ​ ​ ​ ​ ​ (13) ​ ​ ​ ​ ​ (2,267) ​ ​ ​ ​ ​ (153) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (2,433) ​ ​
Ending balance(b)
​ ​ ​ $ 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 ​ ​
 
F-35
 
​ ​ ​
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(c)
​ ​ ​ ​ — ​ ​ ​ ​ ​ (85) ​ ​ ​ ​ ​ (3,097) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (3,182) ​ ​
Ending balance(d)
​ ​ ​ $ 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 $95,245 in 2022 additions, $26,815 was related to acquisitions and $11,295 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. Of the $91,267 in 2020 additions, $46,713 and $10,956 were related to the acquisitions of Carbon and EQT, respectively, while $19,558 was associated with right-of-use asset additions for new and amended leases. Refer to Notes 5 and 20 for additional information regarding acquisitions and leases, respectively. Remaining additions are related to routine capital projects on the Company’s compressor and gathering systems, vehicle and equipment additions.
​
(b)
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.
​
The Company continued to utilize certain fully depreciated assets during the years ended December 31, 2022, 2021 and 2020 with an original cost basis of $9,222, $5,597 and $3,313, respectively.
NOTE 12 — INTANGIBLE ASSETS
Intangible assets consisted of the following for the periods presented:
​ ​ ​
Year Ended December 31, 2022
​
​ ​ ​
Software
​ ​
Other
Acquired
Intangibles
​ ​
Total
​
Costs ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Beginning balance
​ ​ ​ $ 28,095 ​ ​ ​ ​ $ 2,900 ​ ​ ​ ​ $ 30,995 ​ ​
Additions(a)
​ ​ ​ ​ 11,211 ​ ​ ​ ​ ​ 4,224 ​ ​ ​ ​ ​ 15,435 ​ ​
Disposals
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Ending balance
​ ​ ​ $ 39,306 ​ ​ ​ ​ $ 7,124 ​ ​ ​ ​ $ 46,430 ​ ​
Accumulated amortization ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Beginning balance
​ ​ ​ $ (15,192) ​ ​ ​ ​ $ (1,669) ​ ​ ​ ​ $ (16,861) ​ ​
Period changes
​ ​ ​ ​ (7,325) ​ ​ ​ ​ ​ (1,146) ​ ​ ​ ​ ​ (8,471) ​ ​
Disposals
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Ending balance
​ ​ ​ $ (22,517) ​ ​ ​ ​ $ (2,815) ​ ​ ​ ​ $ (25,332) ​ ​
Net book value
​ ​ ​ $ 16,789 ​ ​ ​ ​ $ 4,309 ​ ​ ​ ​ $ 21,098 ​ ​
 
F-36
 
​ ​ ​
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 years ended December 31, 2022, 2021 and 2020 additions were related to software enhancements and other acquired intangibles.
​
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 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 December 31, 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:
 
F-37
 
​
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. If the Company sells a put option, the Company pays 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.
The following tables summarize the Company’s calculated net fair value of derivative financial instruments as of the reporting date as follows:
 
F-38
 
​ ​ ​ ​ ​ ​ ​ ​ ​
Weighted Average Price per Mcfe(a)
​ ​ ​ ​ ​ ​ ​
NATURAL GAS CONTRACTS
​ ​
Volume
(MMcf)
​ ​
Swaps
​ ​
Sold
Puts
​ ​
Purchased
Puts
​ ​
Sold
Calls
​ ​
Basis
Differential
​ ​
Fair Value at
December 31, 2022
​
2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 214,140 ​ ​ ​ ​ $ 3.65 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (178,637) ​ ​
Three-Way Collars
​ ​ ​ ​ 3,600 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.14 ​ ​ ​ ​ ​ 2.81 ​ ​ ​ ​ ​ 3.61 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (4,022) ​ ​
Stand-Alone Calls, net(b)
​ ​ ​ ​ 22,977 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.86 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (79,836) ​ ​
Basis Swaps
​ ​ ​ ​ 114,174 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (0.66) ​ ​ ​ ​ ​ 19,478 ​ ​
Total 2023 contracts
​ ​ ​ ​ 354,891 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (243,017) ​ ​
2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 166,033 ​ ​ ​ ​ $ 3.15 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (207,798) ​ ​
Stand-Alone Calls
​ ​ ​ ​ 37,698 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.90 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (60,756) ​ ​
Basis Swaps
​ ​ ​ ​ 41,871 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (0.71) ​ ​ ​ ​ ​ 2,165 ​ ​
Total 2024 contracts
​ ​ ​ ​ 245,602 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (266,389) ​ ​
2025 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 140,395 ​ ​ ​ ​ $ 3.09 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (189,632) ​ ​
Stand-Alone Calls
​ ​ ​ ​ 21,900 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 3.00 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (33,444) ​ ​
Total 2025 contracts
​ ​ ​ ​ 162,295 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (223,076) ​ ​
2026 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 109,097 ​ ​ ​ ​ $ 3.15 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (148,011) ​ ​
Stand-Alone Calls
​ ​ ​ ​ 18,250 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.28 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (18,100) ​ ​
2027 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 55,100 ​ ​ ​ ​ $ 3.04 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (77,789) ​ ​
Collars
​ ​ ​ ​ 1,414 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.28 ​ ​ ​ ​ ​ 7.17 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 99 ​ ​
Purchased puts
​ ​ ​ ​ 40,218 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 3.09 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 10,849 ​ ​
Sold puts
​ ​ ​ ​ 16,414 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (990) ​ ​
2028 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 32,190 ​ ​ ​ ​ $ 2.49 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (58,115) ​ ​
Collars
​ ​ ​ ​ 5,382 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.28 ​ ​ ​ ​ ​ 6.90 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 470 ​ ​
Purchased puts
​ ​ ​ ​ 54,203 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 3.04 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 13,586 ​ ​
Sold puts
​ ​ ​ ​ 31,585 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (1,800) ​ ​
2029 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 29,190 ​ ​ ​ ​ $ 2.48 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (53,223) ​ ​
Collars
​ ​ ​ ​ 3,726 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.28 ​ ​ ​ ​ ​ 7.51 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 314 ​ ​
Purchased puts
​ ​ ​ ​ 30,066 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.92 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 6,788 ​ ​
Sold puts
​ ​ ​ ​ 30,066 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (1,820) ​ ​
2030 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 5,450 ​ ​ ​ ​ $ 2.43 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (11,390) ​ ​
Purchased puts
​ ​ ​ ​ 14,492 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2,676 ​ ​
Sold puts
​ ​ ​ ​ 14,492 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (680) ​ ​
Swaptions ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
10/1/2024 – 9/30/2028(c)
​ ​ ​ ​ 14,610 ​ ​ ​ ​ $ 2.91 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (20,105) ​ ​
1/1/2025 – 12/31/2029(d)
​ ​ ​ ​ 36,520 ​ ​ ​ ​ ​ 2.77 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (52,878) ​ ​
4/1/2026 – 3/31/2030(e)
​ ​ ​ ​ 97,277 ​ ​ ​ ​ ​ 2.57 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (156,580) ​ ​
4/1/2030 – 3/31/2032(f)
​ ​ ​ ​ 42,627 ​ ​ ​ ​ ​ 2.57 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (79,688) ​ ​
Total 2026 – 2032 contracts
​ ​ ​ ​ 682,369 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (646,387) ​ ​
Total natural gas contracts
​ ​ ​ ​ 1,445,157 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (1,378,869) ​ ​
​
(a)
Rates have been converted from Btu to Mcfe using a Btu conversion factor of 1.07.
​
(b)
Inclusive of $41,853 in cash settlements for deferred premiums.
​
(c)
Option expires on September 6, 2024.
​
 
F-39
 
(d)
Option expires on December 23, 2024.
​
(e)
Option expires on March 23, 2026.
​
(f)
Option expires on March 22, 2030.
​
​ ​ ​ ​ ​ ​ ​ ​ ​
Weighted Average Price per Bbl
​ ​ ​ ​ ​ ​ ​
NGLs CONTRACTS
​ ​
Volume
(MBbls)
​ ​
Swaps
​ ​
Sold
Puts
​ ​
Purchased
Puts
​ ​
Sold
Calls
​ ​
Fair Value at
December 31, 2022
​
2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps(a)
​ ​ ​ ​ 3,818 ​ ​ ​ ​ $ 36.65 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (4,586) ​ ​
Stand-Alone Calls
​ ​ ​ ​ 365 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 24.78 ​ ​ ​ ​ ​ (3,562) ​ ​
2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps(a)
​ ​ ​ ​ 1,973 ​ ​ ​ ​ $ 34.84 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (929) ​ ​
Stand-Alone Calls
​ ​ ​ ​ 915 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 31.29 ​ ​ ​ ​ ​ (7,317) ​ ​
2025 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps(a)
​ ​ ​ ​ 1,861 ​ ​ ​ ​ $ 30.22 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (6,002) ​ ​
2026 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps(a)
​ ​ ​ ​ 1,058 ​ ​ ​ ​ $ 27.66 ​ ​ ​ ​ $  — ​ ​ ​ ​ $  — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (1,062) ​ ​
Total NGLs contracts
​ ​ ​ ​ 9,990 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (23,458) ​ ​
​
(a)
Certain portions of NGLs swaps include effects of purchased oil swaps intended to provide a final NGLs price as a percentage of WTI.
​
​ ​ ​ ​ ​ ​ ​ ​ ​
Weighted Average Price per Bbl
​ ​ ​ ​ ​ ​ ​
OIL CONTRACTS
​ ​
Volume
(MBbls)
​ ​
Swaps
​ ​
Sold
Puts
​ ​
Purchased
Puts
​ ​
Sold
Calls
​ ​
Fair Value at
December 31, 2022
​
2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 890 ​ ​ ​ ​ $ 69.39 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (8,210) ​ ​
Sold Calls
​ ​ ​ ​ 117 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 53.20 ​ ​ ​ ​ ​ (3,057) ​ ​
2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 431 ​ ​ ​ ​ $ 62.54 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (4,576) ​ ​
Sold Calls
​ ​ ​ ​ 183 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 70.00 ​ ​ ​ ​ ​ (2,521) ​ ​
2025 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 366 ​ ​ ​ ​ $ 59.01 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (3,530) ​ ​
2026 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 283 ​ ​ ​ ​ $ 59.48 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (1,749) ​ ​
2027 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 162 ​ ​ ​ ​ $ 58.60 ​ ​ ​ ​ $  — ​ ​ ​ ​ $  — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (768) ​ ​
Total oil contracts
​ ​ ​ ​ 2,432 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (24,411) ​ ​
INTEREST
​ ​
Principal Hedged
​ ​
Fixed-Rate
​ ​
Fair Value at
December 31, 2022
​
2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
SOFR Interest Rate Swap
​ ​ ​ $ 400,000 ​ ​ ​ ​ ​ 1.73% ​ ​ ​ ​ $ (3,228) ​ ​
Net fair value of derivative financial instruments as of December 31, 2022
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (1,429,966) ​ ​
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
 
F-40
 
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 periods presented:
Derivative Financial Instruments
​ ​
Consolidated Statement of
Financial Position
​ ​
December 31, 2022
​ ​
December 31, 2021
​
Assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Non-current assets
​ ​
Derivative financial instruments
​ ​ ​ $ 13,936 ​ ​ ​ ​ $ 219 ​ ​
Current assets
​ ​
Derivative financial instruments
​ ​ ​ ​ 27,739 ​ ​ ​ ​ ​ 1,052 ​ ​
Total assets
​ ​ ​ ​ ​ ​ $ 41,675 ​ ​ ​ ​ $ 1,271 ​ ​
Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Non-current liabilities
​ ​
Derivative financial instruments
​ ​ ​ $ (1,177,801) ​ ​ ​ ​ $ (556,982) ​ ​
Current liabilities
​ ​
Derivative financial instruments
​ ​ ​ ​ (293,840) ​ ​ ​ ​ ​ (251,687) ​ ​
Total liabilities
​ ​ ​ ​ ​ ​ $ (1,471,641) ​ ​ ​ ​ $ (808,669) ​ ​
Net assets (liabilities): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Net assets (liabilities) – non-current
​ ​
Other non-current assets (liabilities)
​ ​ ​ $ (1,163,865) ​ ​ ​ ​ $ (556,763) ​ ​
Net assets (liabilities) − current 
​ ​
Other current assets (liabilities)
​ ​ ​ ​ (266,101) ​ ​ ​ ​ ​ (250,635) ​ ​
Total net assets (liabilities)
​ ​ ​ ​ ​ ​ $ (1,429,966) ​ ​ ​ ​ $ (807,398) ​ ​
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 as of the periods indicated:
​ ​ ​
December 31, 2022
​
​ ​ ​
Presented
without
Effects of
Netting
​ ​
Effects of
Netting
​ ​
As
Presented
with
Effects of
Netting
​
Non-current assets
​ ​ ​ $ 101,275 ​ ​ ​ ​ $ (87,339) ​ ​ ​ ​ $ 13,936 ​ ​
Current assets
​ ​ ​ ​ 92,611 ​ ​ ​ ​ ​ (64,872) ​ ​ ​ ​ ​ 27,739 ​ ​
Total assets
​ ​ ​ $ 193,886 ​ ​ ​ ​ $ (152,211) ​ ​ ​ ​ $ 41,675 ​ ​
Non-current liabilities
​ ​ ​ ​ (1,261,369) ​ ​ ​ ​ ​ 83,568 ​ ​ ​ ​ ​ (1,177,801) ​ ​
Current liabilities
​ ​ ​ ​ (362,483) ​ ​ ​ ​ ​ 68,643 ​ ​ ​ ​ ​ (293,840) ​ ​
Total liabilities
​ ​ ​ $ (1,623,852) ​ ​ ​ ​ $ 152,211 ​ ​ ​ ​ $ (1,471,641) ​ ​
Total net assets (liabilities)
​ ​ ​ $ (1,429,966) ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (1,429,966) ​ ​
​ ​ ​
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) ​ ​
 
F-41
 
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, 2022
​ ​
December 31, 2021
​ ​
December 31, 2020
​
Net gain (loss) on commodity derivatives settlements(a)
​ ​ ​ $ (895,802) ​ ​ ​ ​ $ (320,656) ​ ​ ​ ​ $ 144,600 ​ ​
Net gain (loss) on interest rate swaps(a)
​ ​ ​ ​ (1,434) ​ ​ ​ ​ ​ (530) ​ ​ ​ ​ ​ (202) ​ ​
Gain (loss) on foreign currency hedges(a)
​ ​ ​ ​ — ​ ​ ​ ​ ​ (1,227) ​ ​ ​ ​ ​ — ​ ​
Total gain (loss) on settled derivative instruments
​ ​ ​ $ (897,236) ​ ​ ​ ​ $ (322,413) ​ ​ ​ ​ $ 144,398 ​ ​
Gain (loss) on fair value adjustments of unsettled financial instruments(b)
​ ​ ​ ​ (861,457) ​ ​ ​ ​ ​ (652,465) ​ ​ ​ ​ ​ (238,795) ​ ​
Total gain (loss) on derivative financial instruments
​ ​ ​ $ (1,758,693) ​ ​ ​ ​ $ (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 financings 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. 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.
2022 Modifications and Extinguishments
In February 2022, the Company adjusted portions of its commodity derivative portfolio across its legal entities to ensure that it maintained 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 adjustments by entering into new commodity derivative 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, driven primarily by the purchase of long-dated puts for ABS III and ABS IV that collectively increased the value of the Company’s derivative position by an equal amount, and were required under the respective ABS III and ABS IV indentures. 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, and in October 2022 the Company completed the ABS V and ABS VI financing arrangements, respectively, and made similar commodity 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, driven primarily by the purchase of long-dated puts that increased the value of the Company’s derivative position by an equal amount, and were required under the ABS V indenture. Under the ABS VI financing, the Company paid $32,242 from the proceeds of the financing to increase the value of certain pre-existing derivative contracts that were novated to the ABS VI legal entity at closing. The Company recorded the payments as new derivative financial instruments on its Consolidated Statement of Financial Position.
Refer to Note 21 for additional information regarding ABS financing arrangements.
 
F-42
 
Other commodity derivative contract modifications made during the normal course of business for the year ended December 31, 2022 totaled $133,573 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. These modifications were primarily associated with elevating the Company’s weighted average hedge floor to take advantage of the high price environment experienced in 2022 over a longer term. The trades were primarily comprised of swap enhancements and the extinguishment of standalone call options.
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 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.
Refer to Note 5 for additional information regarding acquisitions.
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.
2020 Modifications and Extinguishments
During the year ended December 31, 2020, the Company paid $10,963 to modify certain derivative contracts. Modifications include the quantum of production subject to contracts, the swap or floor price of certain contracts and similar elements of it. Of the $10,963, $3,240 related to the Company’s ABS II financing transaction, which refinanced a portion of its Credit Facility borrowings. To facilitate the price protection for ABS II, the Company initiated the necessary derivative contracts required by the lender with a member of its existing Credit Facility. After closing ABS II, the Company novated certain contracts to the legal entity holding ABS II. The remaining payments of $7,723 related to offsetting positions for derivative contracts on its Credit Facility, which the Company recorded as new derivative financial instruments 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 of the periods presented:
 
F-43
 
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​
Commodity receivables(a)
​ ​ ​ $ 285,700 ​ ​ ​ ​ $ 275,295 ​ ​
Other receivables
​ ​ ​ ​ 20,022 ​ ​ ​ ​ ​ 13,768 ​ ​
Total trade receivables
​ ​ ​ $ 305,722 ​ ​ ​ ​ $ 289,063 ​ ​
Allowance for credit losses(b)
​ ​ ​ ​ (8,941) ​ ​ ​ ​ ​ (6,141) ​ ​
Total trade receivables, net
​ ​ ​ $ 296,781 ​ ​ ​ ​ $ 282,922 ​ ​
​
(a)
Includes trade receivables and accrued revenues. The increase in commodity receivables reflects the increase in commodity pricing over the periods presented, as well as our growth through acquisitions.
​
(b)
The allowance for credit losses was primarily related to amounts due from joint interest owners. The year-over-year increase from 2021 to 2022 was primarily associated with acquired receivables that allowances were established for as part of purchase accounting.
​
NOTE 15 — OTHER ASSETS
The following table includes details of other assets as of the periods presented:
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​
Other non-current assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Other non-current assets
​ ​ ​ $ 4,351 ​ ​ ​ ​ $ 3,635 ​ ​
Total other non-current assets
​ ​ ​ $ 4,351 ​ ​ ​ ​ $ 3,635 ​ ​
Other current assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Prepaid expenses
​ ​ ​ $ 5,255 ​ ​ ​ ​ $ 5,126 ​ ​
Other assets(a)
​ ​ ​ ​ — ​ ​ ​ ​ ​ 25,004 ​ ​
Inventory
​ ​ ​ ​ 9,227 ​ ​ ​ ​ ​ 9,444 ​ ​
Total other current assets
​ ​ ​ $ 14,482 ​ ​ ​ ​ $ 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.
​
NOTE 16 — SHARE CAPITAL
The Company has one class of common shares which carry the right to one vote at annual general meetings of the Company. As of December 31, 2022, the Company had no limit on the amount of authorized share capital and all shares in issue were fully paid.
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.
 
F-44
 
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 year ended December 31, 2022, the EBT purchased 15,790 shares at an average price per share of $1.44 (approximately £1.24) for a total consideration of $22,931 (approximately £19,388). During the year ended year ended December 31, 2022, the EBT reissued 1,760 to settle vested share-based awards. As of December 31, 2022, the EBT held 14,030 shares. Refer to Note 17 for additional information related to share-based compensation.
Repurchase of Shares
During the year ended December 31, 2022, the Company repurchased 7,995 treasury shares at an average price of $1.37 totaling $11,760. No treasury shares were repurchased during the year ended December 31, 2021. 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.
The Company has accounted for the repurchase of these shares as a reduction to the treasury reserve. All repurchased treasury shares were cancelled upon repurchase and their par value of $80 has been retired into the capital redemption reserve included within share based payments and other reserves in the Consolidated Statement of Financial Position.
Settlement of Warrants
In July 2022, the Company entered into an agreement to cancel 132 warrants (the “Warrants”) held by certain former Mirabaud Securities Limited (“Mirabaud”) employees for an aggregate principal amount of approximately $56 (approximately £46). The former employees surrendered the Warrants to the Company for cancellation. Concurrently, the Company entered into an agreement to exercise 224 Warrants held by certain former Mirabaud employees for an aggregate principal amount of approximately $201 (approximately £166). The former employees surrendered the Warrants to the Company for cancellation in exchange for an equivalent number of shares of common stock. Following this purchase and exercise, no warrants remain outstanding.
In February 2022, the Company entered into an agreement to cancel 477 Warrants held by certain former Mirabaud Securities Limited (“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 £187). The former employees surrendered the Warrants to the Company for cancellation in exchange for an equivalent number of shares of common stock. Following this purchase and exercise, 355 warrants remained outstanding.
In January 2021, the Company entered into an agreement to cancel 2,377 Warrants held by 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 remained outstanding.
 
F-45
 
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
​
Year Ended December 31, 2019
​ ​ ​ ​ 655,730 ​ ​ ​ ​ $ 8,800 ​ ​ ​ ​ $ 760,543 ​ ​
Issuance of share capital (equity placement)
​ ​ ​ ​ 64,281 ​ ​ ​ ​ ​ 791 ​ ​ ​ ​ ​ 80,616 ​ ​
Issuance of share capital (equity compensation)
​ ​ ​ ​ 324 ​ ​ ​ ​ ​ 3 ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares (share buyback program)
​ ​ ​ ​ (12,958) ​ ​ ​ ​ ​ (74) ​ ​ ​ ​ ​ — ​ ​
Balance as of December 31, 2020
​ ​ ​ ​ 707,377 ​ ​ ​ ​ ​ 9,520 ​ ​ ​ ​ ​ 841,159 ​ ​
Issuance of share capital (equity placement)
​ ​ ​ ​ 141,541 ​ ​ ​ ​ ​ 2,044 ​ ​ ​ ​ ​ 211,800 ​ ​
Issuance of share capital (equity compensation)
​ ​ ​ ​ 737 ​ ​ ​ ​ ​ 7 ​ ​ ​ ​ ​ — ​ ​
Balance as of December 31, 2021
​ ​ ​ ​ 849,655 ​ ​ ​ ​ ​ 11,571 ​ ​ ​ ​ ​ 1,052,959 ​ ​
Issuance of share capital (settlement of warrants)
​ ​ ​ ​ 513 ​ ​ ​ ​ ​ 5 ​ ​ ​ ​ ​ — ​ ​
Issuance of share capital (equity compensation)
​ ​ ​ ​ 792 ​ ​ ​ ​ $ 7 ​ ​ ​ ​ $ — ​ ​
Issuance of EBT shares (equity compensation)
​ ​ ​ ​ 1,760 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares (EBT)
​ ​ ​ ​ (15,790) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares (share buyback program)
​ ​ ​ ​ (7,995) ​ ​ ​ ​ $ (80) ​ ​ ​ ​ $ — ​ ​
Balance as of December 31, 2022
​ ​ ​ ​ 828,935 ​ ​ ​ ​ $ 11,503 ​ ​ ​ ​ $ 1,052,959 ​ ​
Subsequent Events
In February 2023, the Company placed 128,444 new shares at $1.27 per share (£1.05) to raise gross proceeds of $162,757 (approximately £134,866). Associated costs of the placing were $6,479. The Company used the proceeds to fund the Tanos II transaction, discussed in Note 5.
NOTE 17 — NON-CASH SHARE-BASED COMPENSATION
Equity Incentive Plan
The 2017 Equity Incentive Plan (the “Plan”), as amended through April 27, 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, PSUs and dividend equivalent units (“DEUs”), that are granted under the Plan. As of December 31, 2022, 11,882 shares have vested and been issued to Plan participants, 25,856 shares have been granted but remain unvested and 4,230 DEUs have accrued and remain unvested. 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 DEUs have accrued and remain unvested.
 
F-46
 
Options Awards
The following table summarizes Options award activity for the respective periods presented:
​ ​ ​
Number of
Options(a)
​ ​
Weighted Average
Grant Date
Fair Value
per Share
​
Balance as of December 31, 2019
​ ​ ​ ​ 23,670 ​ ​ ​ ​ $ 0.42 ​ ​
Granted
​ ​ ​
​
—
 ​ ​ ​ ​
$
—
 ​ ​
Exercised(b)
​ ​ ​
​
—
 ​ ​ ​ ​
$
—
 ​ ​
Forfeited
​ ​ ​
​
(650)
​ ​ ​ ​
$
0.37
 ​ ​
Balance as of December 31, 2020
​ ​ ​ ​ 23,020 ​ ​ ​ ​ $ 0.43 ​ ​
Granted
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Exercised(b)
​ ​ ​ ​ (833) ​ ​ ​ ​ ​ 0.33 ​ ​
Forfeited
​ ​ ​ ​ (300) ​ ​ ​ ​ ​ 0.59 ​ ​
Balance as of December 31, 2021
​ ​ ​ ​ 21,887 ​ ​ ​ ​ $ 0.43 ​ ​
Granted
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Exercised(b)
​ ​ ​ ​ (7,973) ​ ​ ​ ​ ​ 0.33 ​ ​
Forfeited
​ ​ ​ ​ (6,400) ​ ​ ​ ​ ​ 0.57 ​ ​
Balance as of December 31, 2022
​ ​ ​ ​ 7,514 ​ ​ ​ ​ $ 0.41 ​ ​
​
(a)
As of December 31, 2022 and 2021, 380 and 4,033 Options were exercisable, respectively. As of December 31, 2022 all remaining Options outstanding have an exercise price ranging from £0.84 to £1.20 and a weighted average remaining contractual life of 5.6 years.
​
(b)
The weighted average exercise date share price was $1.62 and $1.74 for Options exercised during 2022 and 2021, respectively.
​
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, 2022, 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 ​ ​
Granted
​ ​ ​ ​ 3,970 ​ ​ ​ ​ ​ 1.38 ​ ​
Vested
​ ​ ​ ​ (1,275) ​ ​ ​ ​ ​ 1.30 ​ ​
Forfeited
​ ​ ​ ​ (89) ​ ​ ​ ​ ​ 1.36 ​ ​
Balance as of December 31, 2022
​ ​ ​ ​ 6,731 ​ ​ ​ ​ $ 1.38 ​ ​
 
F-47
 
RSUs cliff- or ratably-vest based on service conditions. 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.
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 31 December 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 ​ ​
Granted
​ ​ ​ ​ 4,640 ​ ​ ​ ​ ​ 1.40 ​ ​
Vested
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Forfeited
​ ​ ​ ​ (74) ​ ​ ​ ​ ​ 1.30 ​ ​
Balance as of December 31, 2022
​ ​ ​ ​ 11,611 ​ ​ ​ ​ $ 1.25 ​ ​
PSUs cliff-vest based on 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, and methane intensity reduction over three years. 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, 2022
​ ​
December 31, 2021
​
Risk-free rate of interest
​ ​
1.3%
​ ​
0.2%
​
Volatility(a) ​ ​
37%
​ ​
35%
​
Correlation with comparator group range
​ ​
0.01 – 0.36
​ ​
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, 2022
​ ​
December 31, 2021
​ ​
December 31, 2020
​
Options
​ ​ ​ $ (749) ​ ​ ​ ​ $ 2,115 ​ ​ ​ ​ $ 2,553 ​ ​
RSUs
​ ​ ​ ​ 4,210 ​ ​ ​ ​ ​ 2,346 ​ ​ ​ ​ ​ 1,367 ​ ​
PSUs
​ ​ ​ ​ 4,590 ​ ​ ​ ​ ​ 2,939 ​ ​ ​ ​ ​ 1,116 ​ ​
Total share-based compensation expense
​ ​ ​ $ 8,051 ​ ​ ​ ​ $ 7,400 ​ ​ ​ ​ $ 5,036 ​ ​
 
F-48
 
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
​
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 ​ ​
Declared on May 16,
2022
​ ​ ​ $ 0.0425 ​ ​ ​ ​ £ 0.0366 ​ ​ ​
September 2, 2022
​ ​
September 26, 2022
​ ​ ​ ​ 845,881 ​ ​ ​ ​ $ 35,950 ​ ​
Declared on August 8,
2022
​ ​ ​ $ 0.0425 ​ ​ ​ ​ £ 0.0345 ​ ​ ​
November 25, 2022
​ ​
December 28, 2022
​ ​ ​ ​ 828,935 ​ ​ ​ ​ ​ 35,230 ​ ​
Paid during the year ended
December 31, 2022
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 143,455 ​ ​
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 during the year ended
December 31, 2021
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ 130,239 ​ ​
Declared on December 10,
2019
​ ​ ​ $ 0.0350 ​ ​ ​ ​ £ 0.0276 ​ ​ ​
March 6, 2020
​ ​
March 27, 2020
​ ​ ​ ​ 642,805 ​ ​ ​ ​ $ 22,498 ​ ​
Declared on March 9, 2020
​ ​ ​ $ 0.0350 ​ ​ ​ ​ £ 0.0274 ​ ​ ​
May 29, 2020
​ ​
June 26, 2020
​ ​ ​ ​ 707,086 ​ ​ ​ ​ ​ 24,748 ​ ​
Declared on May 4,
2020
​ ​ ​ $ 0.0350 ​ ​ ​ ​ £ 0.0269 ​ ​ ​
September 4, 2020
​ ​
September 25, 2020
​ ​ ​ ​ 707,274 ​ ​ ​ ​ ​ 24,755 ​ ​
Declared on August 10, 2020
​ ​ ​ $ 0.0375 ​ ​ ​ ​ £ 0.0278 ​ ​ ​
November 27, 2020
​ ​
December 18, 2020
​ ​ ​ ​ 707,377 ​ ​ ​ ​ ​ 26,526 ​ ​
Paid during the year ended
December 31, 2020
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ 98,527 ​ ​
On November 14, 2022 the Company proposed a dividend of $0.04375 per share. The dividend will be paid on March 28, 2023 to shareholders on the register on March 3, 2023. 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, 2022.
Dividends are waived on shares held in the EBT.
Subsequent Events
On March 21, 2023 the Directors recommended a dividend of $0.04375 per share. The dividend will be paid on June 30, 2023 to shareholders on the register on May 26, 2023, 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 of December 31, 2022.
NOTE 19 — ASSET RETIREMENT OBLIGATIONS
The Company records a liability for the present value of the estimated future decommissioning costs on its natural gas and oil properties, which it expects to incur at the end of the long-producing life of a well.
 
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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 by approximately 2095 consistent with the Company’s reserve calculations which were independently evaluated by the Company’s independent engineers for the years ended December 31, 2022, 2021 and 2020. 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. No such contractual agreements or statutes that would impose material obligations on the Company were in place for the Company’s production facilities and pipelines for the years ended December 31, 2022 and 2021.
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 U.S. 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 U.S. 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, 2021 and 2020 was 3.6%, 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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Balance at beginning of period
​ ​ ​ $ 525,589 ​ ​ ​ ​ $ 346,124 ​ ​ ​ ​ $ 199,521 ​ ​
Additions(a)
​ ​ ​ ​ 24,395 ​ ​ ​ ​ ​ 96,292 ​ ​ ​ ​ ​ 26,995 ​ ​
Accretion
​ ​ ​ ​ 27,569 ​ ​ ​ ​ ​ 24,396 ​ ​ ​ ​ ​ 15,424 ​ ​
Asset retirement costs
​ ​ ​ ​ (4,889) ​ ​ ​ ​ ​ (2,879) ​ ​ ​ ​ ​ (2,442) ​ ​
Disposals(b)
​ ​ ​ ​ (16,779) ​ ​ ​ ​ ​ (16,500) ​ ​ ​ ​ ​ (3,838) ​ ​
Revisions to estimate(c)
​ ​ ​ ​ (98,802) ​ ​ ​ ​ ​ 78,156 ​ ​ ​ ​ ​ 110,464 ​ ​
Balance at end of period
​ ​ ​ $ 457,083 ​ ​ ​ ​ $ 525,589 ​ ​ ​ ​ $ 346,124 ​ ​
Less: Current asset retirement obligations
​ ​ ​ ​ 4,529 ​ ​ ​ ​ ​ 3,399 ​ ​ ​ ​ ​ 1,882 ​ ​
Non-current asset retirement obligations
​ ​ ​ $ 452,554 ​ ​ ​ ​ $ 522,190 ​ ​ ​ ​ $ 344,242 ​ ​
​
(a)
Refer to Note 5 for additional information regarding acquisitions and divestitures.
​
(b)
Associated with the divestiture of natural gas and oil properties in the normal course of business. Refer to Note 10 for additional information.
​
(c)
As of December 31, 2022, the Company performed normal revisions to its asset retirement obligations, which resulted in a $98,802 decrease in the liability. This decrease was comprised of a $144,656 decrease attributable to a higher discount rate. The higher discount rate was a result of macroeconomic factors spurred by the increase in bond yields which have elevated with U.S. treasuries to combat the current inflationary environment. Partially offsetting this decrease was $29,357 in cost revisions based on the Company’s recent asset retirement experiences and a $16,497 timing revision for the acceleration of the Company’s retirement plans made possible by the recent asset retirement acquisitions that improve the Company’s asset retirement capacity through the growth of its operational capabilities. As of December 31, 2021, the Company performed normal revisions to its asset retirement obligations,
​
 
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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 asset retirement program and efficiencies gained.As of 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 of December 31, 2022.
ARO Sensitivity
​ ​
+10%
​ ​
-10%
​
Discount rate
​ ​ ​ $ (46,122) ​ ​ ​ ​ $ 53,417 ​ ​
Timing
​ ​ ​ ​ 27,998 ​ ​ ​ ​ ​ (30,755) ​ ​
Cost
​ ​ ​ ​ 45,708 ​ ​ ​ ​ ​ (45,708) ​ ​
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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Balance at beginning of period
​ ​ ​ $ 27,804 ​ ​ ​ ​ $ 18,878 ​ ​ ​ ​ $ 1,813 ​ ​
Additions(a)
​ ​ ​ ​ 11,269 ​ ​ ​ ​ ​ 16,482 ​ ​ ​ ​ ​ 19,820 ​ ​
Interest expense(b)
​ ​ ​ ​ 1,022 ​ ​ ​ ​ ​ 1,050 ​ ​ ​ ​ ​ 929 ​ ​
Cash outflows
​ ​ ​ ​ (11,233) ​ ​ ​ ​ ​ (8,606) ​ ​ ​ ​ ​ (3,684) ​ ​
Balance at end of period
​ ​ ​ $ 28,862 ​ ​ ​ ​ $ 27,804 ​ ​ ​ ​ $ 18,878 ​ ​
Classified as: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Current liability
​ ​ ​ $ 9,293 ​ ​ ​ ​ $ 9,627 ​ ​ ​ ​ $ 5,013 ​ ​
Non-current liability
​ ​ ​ ​ 19,569 ​ ​ ​ ​ ​ 18,177 ​ ​ ​ ​ ​ 13,865 ​ ​
Total ​ ​ ​ $ 28,862 ​ ​ ​ ​ $ 27,804 ​ ​ ​ ​ $ 18,878 ​ ​
​
(a)
The $11,269 in lease additions during the year ended December 31, 2022, was primarily attributable to the expansion of the Company’s fleet due to its growth. Of the $16,482 in lease additions during the year ended December 31, 2021, $8,062 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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Set out below is the movement in the right-of-use assets:
​ ​ ​
Right-of-Use Assets
​
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Balance at beginning of period
​ ​ ​ $ 26,908 ​ ​ ​ ​ $ 18,026 ​ ​ ​ ​ $ 1,868 ​ ​
Additions(a)
​ ​ ​ ​ 11,295 ​ ​ ​ ​ ​ 16,554 ​ ​ ​ ​ ​ 19,558 ​ ​
Depreciation
​ ​ ​ ​ (10,244) ​ ​ ​ ​ ​ (7,672) ​ ​ ​ ​ ​ (3,400) ​ ​
Balance at end of period
​ ​ ​ $ 27,959 ​ ​ ​ ​ $ 26,908 ​ ​ ​ ​ $ 18,026 ​ ​
Classified as: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Motor vehicles
​ ​ ​ $ 23,782 ​ ​ ​ ​ $ 19,149 ​ ​ ​ ​ $ 14,614 ​ ​
Midstream
​ ​ ​ ​ 3,801 ​ ​ ​ ​ ​ 6,502 ​ ​ ​ ​ ​ 2,496 ​ ​
Buildings and leasehold improvements
​ ​ ​ ​ 376 ​ ​ ​ ​ ​ 1,257 ​ ​ ​ ​ ​ 916 ​ ​
Total ​ ​ ​ $ 27,959 ​ ​ ​ ​ $ 26,908 ​ ​ ​ ​ $ 18,026 ​ ​
​
(a)
The $11,295 in lease additions during the year ended December 31, 2022 was attributable to the expansion of the Company’s fleet due to its growth. Of the $16,554 in lease additions during the year ended December 31, 2021, $8,062 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, 2022
​ ​
December 31, 2021
​ ​
December 31, 2020
​
Discount rates range
​ ​
1.8% – 6.3%
​ ​
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 short term compressor rentals and were $25,153, $15,362 and $9,799 for the years ended December 31, 2022, 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,
2022
​ ​
December 31,
2021
​
Not Later Than One Year
​ ​ ​ $ 9,293 ​ ​ ​ ​ $ 9,627 ​ ​
Later Than One Year and Not Later Than Five Years
​ ​ ​ ​ 19,569 ​ ​ ​ ​ ​ 18,177 ​ ​
Later Than Five Years
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Total ​ ​ ​ $ 28,862 ​ ​ ​ ​ $ 27,804 ​ ​
 
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NOTE 21 — BORROWINGS
The Company’s borrowings consist of the following amounts as of the reporting date as follows:
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​
Credit Facility (Interest rate of 7.42% and 3.50%, respectively)(a)
​ ​ ​ $ 56,000 ​ ​ ​ ​ $ 570,600 ​ ​
ABS I Notes (Interest rate of 5.00%)
​ ​ ​ ​ 125,864 ​ ​ ​ ​ ​ 155,266 ​ ​
ABS II Notes (Interest rate of 5.25%)
​ ​ ​ ​ 147,458 ​ ​ ​ ​ ​ 169,320 ​ ​
ABS III Notes (Interest rate of 4.875%)
​ ​ ​ ​ 319,856 ​ ​ ​ ​ ​ — ​ ​
ABS IV Notes (Interest rate of 4.95%)
​ ​ ​ ​ 130,144 ​ ​ ​ ​ ​ — ​ ​
ABS V Notes (Interest rate of 5.78%)
​ ​ ​ ​ 378,796 ​ ​ ​ ​ ​ — ​ ​
ABS VI Notes (Interest rate of 7.50%)
​ ​ ​ ​ 212,446 ​ ​ ​ ​ ​ — ​ ​
Term Loan I (Interest rate of 6.50%)
​ ​ ​ ​ 120,518 ​ ​ ​ ​ ​ 137,099 ​ ​
Miscellaneous, primarily for real estate, vehicles and equipment
​ ​ ​ ​ 7,084 ​ ​ ​ ​ ​ 9,380 ​ ​
Total borrowings
​ ​ ​ $ 1,498,166 ​ ​ ​ ​ $ 1,041,665 ​ ​
Less: Current portion of long-term debt
​ ​ ​ ​ (271,096) ​ ​ ​ ​ ​ (58,820) ​ ​
Less: Deferred financing costs
​ ​ ​ ​ (48,256) ​ ​ ​ ​ ​ (26,413) ​ ​
Less: Original issue discounts
​ ​ ​ ​ (9,581) ​ ​ ​ ​ ​ (4,897) ​ ​
Total non-current borrowings, net
​ ​ ​ $ 1,169,233 ​ ​ ​ ​ $ 951,535 ​ ​
​
(a)
Represents the variable interest rate as of period end.
​
Credit Facility
The Company maintains 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.
In August 2022, the Company amended and restated the credit agreement governing its Credit Facility by entering into the A&R Revolving Credit Facility. The amendment enhanced the alignment with the Company’s stated ESG initiatives by including sustainability performance targets (“SPTs”) similar to those included in the ABS III, IV, V and VI notes, extended the maturity of the Credit Facility to August 2026, removed DGOC as a credit party from the Credit Facility, and reaffirmed the borrowing base of $300,000 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 is now associated solely with DP RBL CO LLC, the borrower, a subsidiary of DGOC, the prior 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: The Company’s consolidated Scope 1 emissions and Scope 2 emissions, each measured as MT CO2e per MMcfe;
​
•
Asset Retirement Performance: The number of wells the Company successfully retires during any fiscal year; and
​
•
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 the Company has publicly set for itself. The economic repercussions of achieving or
 
F-53
 
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 the Company’s performance of the SPTs. Though the Company is not required to do so, it intends to disclose this certification on an annual basis in our semi-annual or annual report, as determined by the timing of such certification, along with an overall ESG update.
Additional amendments to the Credit Facility in October 2022 and November 2022 lowered the borrowing base to $250,000 to account for the net impact of ABS VI and the ConocoPhillips acquisition. In March 2023, the Company upsized the borrowing base on the Credit Facility to $375,000. The next redetermination is expected to occur in Spring 2024.
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. Available borrowings under the Credit Facility were $183,332 as of December 31, 2022 which considers the impact of $10,668 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 DP RBL Co LLC 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 December 31, 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 2020 Carbon and EQT acquisitions. The Term Loan I is secured by certain producing assets acquired in connection with the Carbon, Blackbeard and Tapstone acquisitions.
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 years ended December 31, 2022, 2021 and 2020, the Company incurred $8,643, $9,860 and $6,371 in interest related to the Term Loan I, respectively. The fair value of the Term Loan I approximates the carrying value as of December 31, 2022.
ABS I Notes
In November 2019, the Company 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 $200,000 at par. 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. During the years ended December 31, 2022, 2021 and 2020, the Company incurred $7,110, $8,460 and $9,661 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% rate per annum. The fair value of the ABS I Notes approximates the carrying value as of December 31, 2022. In the event that ABS I has cash flow in excess of the required payments, ABS I 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) with respect to any payment date prior to March 1, 2030, (i) if the debt service coverage ratio (the “DSCR”) as of such payment date is greater than or
 
F-54
 
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 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, the Company 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 $200,000. The ABS II Notes 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 with an amortizing maturity of September 2028. Interest and principal payments on the ABS II Notes are payable on a monthly basis. During the years ended December 31, 2022, 2021 and 2020, the Company incurred $9,286, $10,530 and $7,563 in interest related to the ABS II Notes, respectively. The fair value of the ABS II Notes approximates the carrying value as of December 31, 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 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 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 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, the Company 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 $365,000 at par. The ABS III Notes are secured by certain of the Company’s upstream producing, 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 year ended December 31, 2022, the Company incurred $15,325 in interest related to the ABS III Notes. The fair value of the ABS III Notes approximates the carrying value as of December 31, 2022.
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 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%.
 
F-55
 
In addition, in connection with the issuance of the ABS III Notes, the Company 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 the Company meeting or exceeding any sustainability performance metrics but rather an overall assessment of the Company’s 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 the Company’s Credit Facility. The Company informs the ABS III note holders in monthly note holder 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 the Company is not required to publicly release this score, it will provide the score as of the date of its semi-annual 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, the Company 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 $160,000 at par. The ABS IV Notes are secured by a portion of the upstream producing assets acquired in connection with the Blackbeard Acquisition.
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 year ended December 31, 2022, the Company incurred $6,235 in interest related to the ABS IV Notes. The fair value of the ABS IV Notes approximates the carrying value as of December 31, 2022.
In the event that ABS IV has cash flow in excess of the required payments, ABS IV 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) 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 of such Payment Date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS IV 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, the Company 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 IV Notes, the interest payable with respect to the subsequent interest accrual period will increase by five basis points. This score is not dependent on the Company meeting or exceeding any sustainability performance metrics but rather an overall assessment of its 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 the Company’s Credit Facility. The Company informs the ABS IV note holders in monthly note holder 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 the Company is not required to publicly release this score, it will provide the score as of the date of its semi-annual 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 $445,000 at par. 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.
 
F-56
 
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 year ended December 31, 2022, the Company incurred $14,319 in interest related to the ABS V Notes. The fair value of the ABS V Notes approximates the carrying value as of December 31, 2022.
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 of such payment date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS V 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.
The ABS V Notes contain two SPTs. The Company must achieve, and have certified by April 28, 2027 (1) a reduction in Scope 1 and Scope 2 GHG emissions intensity to 2.85 MT CO2e/MMcfe, and/or (2) a reduction in Scope 1 natural gas emissions intensity to 1.12 MT CO2e/MMcfe. For each of these SPTs that the Company fails to meet, or have certified by an external verifier that it has 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 the Company’s performance of the above SPTs by the applicable deadlines. Though the Company is not required to do so, it intends to disclose this certification on an annual basis in its semi-annual or annual report, as determined by the timing of such certification, along with an overall ESG update.
ABS VI Notes
In October 2022, the Company formed Diversified ABS VI LLC (“ABS VI”), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary, to issue, jointly with Oaktree, BBB+ rated asset-backed securities in an aggregate principal amount of $460,000 ($235,750 to the Company, before fees, representative of its 51.25% ownership interest in the collateral assets). The ABS VI Notes were issued at a 2.63% discount and are secured primarily by the upstream assets that were jointly acquired with Oaktree in the 2021 Tapstone acquisition. Similar to the accounting treatment described in Note 3 for acquisitions performed in connection with Oaktree, DEC has recorded it’s proportionate share of the note in its Consolidated Statement of Financial Position.
The ABS VI Notes accrue interest at a stated 7.50% rate per annum and have a final maturity date of November 2039 with an amortizing maturity of October 2031. Interest and principal payments on the ABS VI Notes are payable on a monthly basis. During the year ended December 31, 2022, the Company incurred $3,300 in interest related to the ABS VI Notes. The fair value of the ABS VI Notes approximates the carrying value as of December 31, 2022.
Based on whether certain performance metrics are achieved, ABS VI 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 the applicable 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 VI is less than 80%, then 100%, else 0%; and (c) if the LTV for ABS VI is greater than 75%, then 100%, else 0%.
 
F-57
 
In addition, a “second party opinion provider” certified the terms of the ABS VI 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.
The ABS VI Notes contain two SPTs. The Company must achieve, and have certified by May 28, 2027 (1) a reduction in Scope 1 and Scope 2 GHG emissions intensity to 2.85 MT CO2e/MMcfe, and/or (2) a reduction in Scope 1 natural gas emissions intensity to 1.12 MT CO2e/MMcfe. For each of these SPTs that the Company fails to meet, or have certified by an external verifier that it has met, by May 28, 2027, the interest rate payable with respect to the ABS VI Notes will be increased by 25 basis points. In each case, an independent third-party assurance provider will be required to certify the Company’s performance of the above SPTs by the applicable deadlines. Though the Company is not required to do so, it intends to disclose this certification on an annual basis in its semi-annual or annual report, as determined by the timing of such certification, along with an overall ESG update.
Debt Covenants — ABS I, II, III, IV, V and VI 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 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-VI 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 December 31, 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:
​ ​ ​
December 31, 2022
​ ​
December 31, 2021
​
Not later than one year
​ ​ ​ $ 271,096 ​ ​ ​ ​ $ 58,820 ​ ​
Later than one year and not later than five years
​ ​ ​ ​ 778,887 ​ ​ ​ ​ ​ 811,964 ​ ​
Later than five years
​ ​ ​ ​ 448,183 ​ ​ ​ ​ ​ 170,881 ​ ​
Total borrowings
​ ​ ​ $ 1,498,166 ​ ​ ​ ​ $ 1,041,665 ​ ​
 
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The following table represents the Company’s finance costs for each of the periods presented:
​ ​ ​
Year Ended
​
​ ​ ​
December 31, 2022
​ ​
December 31, 2021
​ ​
December 31, 2020
​
Interest expense, net of capitalized and income amounts(a)
​ ​ ​ $ 86,840 ​ ​ ​ ​ $ 42,370 ​ ​ ​ ​ $ 34,391 ​ ​
Amortization of discount and deferred finance costs
​ ​ ​ ​ 13,903 ​ ​ ​ ​ ​ 8,191 ​ ​ ​ ​ ​ 8,334 ​ ​
Other
​ ​ ​ ​ 56 ​ ​ ​ ​ ​ 67 ​ ​ ​ ​ ​ 602 ​ ​
Total finance costs
​ ​ ​ $ 100,799 ​ ​ ​ ​ $ 50,628 ​ ​ ​ ​ $ 43,327 ​ ​
​
(a)
Includes payments related to borrowings and leases.
​
Reconciliation of borrowings arising from financing activities:
​ ​ ​
Year Ended
​
​ ​ ​
December 31, 2022
​ ​
December 31, 2021
​ ​
December 31, 2020
​
Balance at beginning of period
​ ​ ​ $ 1,010,355 ​ ​ ​ ​ $ 717,240 ​ ​ ​ ​ $ 622,288 ​ ​
Acquired as part of a business combination
​ ​ ​ ​ 2,437 ​ ​ ​ ​ ​ 3,801 ​ ​ ​ ​ ​ — ​ ​
Proceeds from borrowings
​ ​ ​ ​ 2,587,554 ​ ​ ​ ​ ​ 1,727,745 ​ ​ ​ ​ ​ 799,650 ​ ​
Repayments of borrowings
​ ​ ​ ​ (2,139,686) ​ ​ ​ ​ ​ (1,436,367) ​ ​ ​ ​ ​ (705,314) ​ ​
Costs incurred to secure financing
​ ​ ​ ​ (34,234) ​ ​ ​ ​ ​ (10,255) ​ ​ ​ ​ ​ (7,799) ​ ​
Amortization of discount and deferred financing costs
​ ​ ​ ​ 13,903 ​ ​ ​ ​ ​ 8,191 ​ ​ ​ ​ ​ 8,334 ​ ​
Cash paid for interest
​ ​ ​ ​ (82,936) ​ ​ ​ ​ ​ (41,623) ​ ​ ​ ​ ​ (34,335) ​ ​
Finance costs and other
​ ​ ​ ​ 82,936 ​ ​ ​ ​ ​ 41,623 ​ ​ ​ ​ ​ 34,416 ​ ​
Balance at end of period
​ ​ ​ $ 1,440,329 ​ ​ ​ ​ $ 1,010,355 ​ ​ ​ ​ $ 717,240 ​ ​
NOTE 22 — 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:
​ ​ ​
December 31, 2022
​ ​
December 31, 2021
​
Trade payables
​ ​ ​ $ 90,437 ​ ​ ​ ​ $ 61,612 ​ ​
Other payables
​ ​ ​ ​ 3,327 ​ ​ ​ ​ ​ 806 ​ ​
Total trade and other payables
​ ​ ​ $ 93,764 ​ ​ ​ ​ $ 62,418 ​ ​
Trade and other payables are unsecured, non-interest bearing and paid as they become due.
 
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NOTE 23 — OTHER LIABILITIES
The following table includes details of other liabilities as of the periods presented:
​ ​ ​
December 31, 2022
​ ​
December 31, 2021
​
Other non-current liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Other non-current liabilities(a)
​ ​ ​ ​ 5,375 ​ ​ ​ ​ ​ 7,775 ​ ​
Total other non-current liabilities
​ ​ ​ $ 5,375 ​ ​ ​ ​ $ 7,775 ​ ​
Other current liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Accrued expenses(b)
​ ​ ​ $ 140,058 ​ ​ ​ ​ $ 139,648 ​ ​
Taxes payable(c)
​ ​ ​ ​ 41,907 ​ ​ ​ ​ ​ 53,629 ​ ​
Net revenue clearing(d)
​ ​ ​ ​ 186,244 ​ ​ ​ ​ ​ 137,366 ​ ​
Asset retirement obligations – current
​ ​ ​ ​ 4,529 ​ ​ ​ ​ ​ 3,399 ​ ​
Revenue to be distributed(e)
​ ​ ​ ​ 90,899 ​ ​ ​ ​ ​ 57,006 ​ ​
Total other current liabilities
​ ​ ​ $ 463,637 ​ ​ ​ ​ $ 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 I deals and 52.50% interest for tranche II deals in the net assets associated with the acquisition while only paying 50% of the total consideration. The upfront promote is intended to compensate the Company for the administrative expansion necessary with acquired growth and is amortized to G&A expense over the life of the promote.
​
(b)
As of December 31, 2022 accrued expenses primarily consisted of $61,896 for hedge settlements payables. The remaining balance consisted of accrued capital projects and operating expenses which naturally increased with our growth. As of December 31, 2021 accrued expenses primarily consisted of the $22,503 for the Carbon and EQT contingent consideration and $44,085 for hedge settlements payables. The remaining balance consisted of accrued capital projects and operating expenses which naturally increased with our growth.
​
(c)
The decrease in taxes payable year-over-year was primarily attributable to the $33,526 capital gain payable on the Tapstone acquisition in 2021 that was paid in 2022 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 were 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, similar to commodity receivables, is a result of higher commodity prices year-over-year, the Company’s growth from acquisitions and Oaktree’s participation in a number of the Company’s 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. As of December 31, 2022, revenue to be distributed increased year-over-year as a result of the Company’s growth and the increase in commodity prices experienced in 2022. As of December 31, 2021, revenue to be distributed increased year-over-year as a result of the Central Region acquisitions while the remaining change was attributable to recurring operating activity and increases in commodity prices.
​
NOTE 24 — 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
 
F-60
 
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
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 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.
Leases
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 determined, the Company uses its incremental borrowing rate.
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, SOFR curve, and volatility factors.
 
F-61
 
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 December 31, 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 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, 2022, 2021 and 2020, the Company recorded $1,036, $9,482 and $2,402, respectively, in revaluations related to contingent consideration associated with asset acquisitions and none, $8,963 and $567, respectively, associated with business combinations.
The contingent consideration represented on the Company’s financial statements is associated with the Carbon and EQT acquisitions. The maximum contingent consideration payment of $15,000 associated with the Carbon acquisitions and the remaining contingent consideration payment of $8,547 associated with EQT acquisitions was made during the year ended December 31, 2022, settling both contingencies in their entirety.
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 there are no remaining contingent payments.
There were no transfers between fair value levels for the year ended December 31, 2022.
 
F-62
 
The following table includes the Company’s financial instruments as at the periods presented:
​ ​ ​
December 31, 2022
​ ​
December 31, 2021
​
Cash and cash equivalents
​ ​ ​ $ 7,329 ​ ​ ​ ​ $ 12,558 ​ ​
Trade receivables and accrued income
​ ​ ​ ​ 296,781 ​ ​ ​ ​ ​ 282,922 ​ ​
Other non-current assets(a)
​ ​ ​ ​ 4,351 ​ ​ ​ ​ ​ 3,635 ​ ​
Other current assets(b)
​ ​ ​ ​ — ​ ​ ​ ​ ​ 25,004 ​ ​
Other non-current liabilities(c)
​ ​ ​ ​ (1,669) ​ ​ ​ ​ ​ (7,775) ​ ​
Other current liabilities(d)
​ ​ ​ ​ (417,201) ​ ​ ​ ​ ​ (334,020) ​ ​
Derivative financial instruments at fair value
​ ​ ​ ​ (1,429,966) ​ ​ ​ ​ ​ (807,398) ​ ​
Leases
​ ​ ​ ​ (28,862) ​ ​ ​ ​ ​ (27,804) ​ ​
Borrowings
​ ​ ​ ​ (1,498,166) ​ ​ ​ ​ ​ (1,041,665) ​ ​
Total ​ ​ ​ $ (3,067,403) ​ ​ ​ ​ $ (1,894,543) ​ ​
​
(a)
Excludes indemnification receivables.
​
(b)
Excludes prepaid expenses, deposits and inventory.
​
(c)
Excludes the long-term portion of the value associated with the upfront promote received from Oaktree.
​
(d)
Includes accrued expenses, net revenue clearing and revenue to be distributed. 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 its 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
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
The Company is subject to market risk exposure related to changes in interest rates. The Company’s borrowings primarily consist of fixed-rate amortizing notes and its variable rate Credit Facility as illustrated below.
 
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​ ​ ​
December 31, 2022
​ ​
December 31, 2021
​
​ ​ ​
Borrowings
​ ​
Interest Rate(a)
​ ​
Borrowings
​ ​
Interest Rate(a)
​
ABS Notes and Term Loan I
​ ​ ​ $ 1,435,082 ​ ​ ​ ​ ​ 5.70% ​ ​ ​ ​ $ 461,685 ​ ​ ​ ​ ​ 5.54% ​ ​
Credit Facility
​ ​ ​ ​ 56,000 ​ ​ ​ ​ ​ 7.42% ​ ​ ​ ​ ​ 570,600 ​ ​ ​ ​ ​ 3.50% ​ ​
​
(a)
The interest rate on the ABS Notes and Term Loan I borrowings represents the weighted average fixed-rate of the notes while the interest rate presented for the Credit Facility represents the floating rate as of December 31, 2022 and 2021, respectively. During the year ended December 31, 2022, the Credit Facility transitioned from LIBOR to SOFR during a the regular spring redetermination. The Company did not experience a material impact from the transition.
​
Refer to Note 21 for additional information regarding the ABS Notes, Term Loan I and Credit Facility. The table below represents the impact of a 100 basis point adjustment in the borrowing 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
​ ​
December 31,
2022
​ ​
December 31,
2021
​
+100 Basis Points
​ ​ ​ $ 560 ​ ​ ​ ​ $ 5,706 ​ ​
-100 Basis Points
​ ​ ​ $ (560) ​ ​ ​ ​ $ (5,706) ​ ​
During 2022, the Company entered into four ABS financing arrangements with fixed interest rates decreasing exposure to rising short-term interest rates. The Company strives to maintain a prudent balance of floating and fixed-rate borrowing exposure, particularly during uncertain market conditions. As part of the Company’s risk mitigation strategy from time to time the Company enters into swap arrangements to increase or decrease exposure to floating or fixed- interest rates to account for changes in the composition of borrowings in its portfolio. As a result, the total principal hedged through the use of derivative financial instruments varies from period to period. The fair value of the Company’s interest rate swaps represents a liability of $3,228 and $91 as of December 31, 2022 and 2021, respectively. Refer to Note 13 for additional information regarding derivative financial instruments.
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, 2022, 2021 and 2020, the Company’s commodity revenue was $1,873,011, $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% in months 25 to 36, of its anticipated production volumes. Refer to Note 13 for additional information regarding derivative financial instruments.
By removing price volatility from a significant portion of the Company’s expected production through 2032, it has mitigated, but not eliminated, the potential effects of changing prices on its operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits the Company would receive from increases in commodity prices.
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 no customers that comprised over 10% of its total trade receivables
 
F-64
 
from customers as of December 31, 2022, and one customer that comprised 13% of its total trade receivables from customers as of December 31, 2021. As of December 31, 2022 and 2021, the Company’s trade receivables from customers were $278,030 and $268,375, 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. As of December 31, 2022 and 2021, the Company’s joint interest receivables were $18,751 and $14,547, respectively.
The majority of trade receivables are current and the Company believes these receivables are collectible. Refer to Note 3 for additional information.
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 following table are the contractual 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, 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Trade and other payables
​ ​ ​ $ 93,764 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ 93,764 ​ ​
Borrowings
​ ​ ​ ​ 271,096 ​ ​ ​ ​ ​ 778,887 ​ ​ ​ ​ ​ 448,183 ​ ​ ​ ​ ​ 1,498,166 ​ ​
Leases
​ ​ ​ ​ 9,293 ​ ​ ​ ​ ​ 19,569 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 28,862 ​ ​
Other liabilities(a)
​ ​ ​ ​ 326,302 ​ ​ ​ ​ ​ 5,375 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 331,677 ​ ​
Total ​ ​ ​ $ 700,455 ​ ​ ​ ​ $ 803,831 ​ ​ ​ ​ $ 448,183 ​ ​ ​ ​ $ 1,952,469 ​ ​
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 ​ ​
​
(a)
Represents accrued expenses and net revenue clearing. 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.
​
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 seeks to maintain a Leverage target at or below 2.5x.
Collateral Risk
The Company has pledged 100% of its 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,
 
F-65
 
which have been pledged under the Credit Facility) as of December 31, 2022 to fulfil the collateral requirements for borrowings under the ABS Notes and Term Loan I. The Company’s remaining natural gas and oil properties collateralize the Credit Facility. The fair value of the borrowings collateral is based on a third-party engineering reserve calculation using estimated cash flows discounted at 10% 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 issues 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, 2022, the Company did not have any material amounts accrued related to litigation or regulatory matters. For any matters not accrued for, 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 and reasonably expected outcomes, 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 the Company’s 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, 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.
NOTE 27 — RELATED PARTY TRANSACTIONS
Martin K. Thomas currently serves as a consultant at Wedlake Bell LLP, the former UK legal advisor to the company, where he was formerly a partner. During 2020, the Company paid fees of $41 (£33) to the former related party legal advisor. The Company had no related party activity in 2022 or 2021.
NOTE 28 — SUBSEQUENT EVENTS
The Company determined the need to disclose the following material transactions that occurred subsequent to December 31, 2022, which have been described within each relevant footnote as follows:
Description
​ ​
Footnote
​
Acquisitions and Divestitures ​ ​ Note 5 ​
Share Capital ​ ​ Note 16 ​
Dividends ​ ​ Note 18 ​
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
 
F-66
 
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 of the years ended December 31, 2020, 2021 and 2022 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.
The following table summarizes the changes in the Company’s net proved reserves for the periods presented, all of which were located in the U.S.:
​ ​ ​
Natural Gas
(MMcf)
​ ​
NGLs
(MBbls)
​ ​
Oil
(MBbls)
​ ​
Total
(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 ​ ​
Revisions of previous estimates(a)
​ ​ ​ ​ 306,696 ​ ​ ​ ​ ​ 11,694 ​ ​ ​ ​ ​ 492 ​ ​ ​ ​ ​ 63,302 ​ ​
Extensions, discoveries and other additions
​ ​ ​ ​ 13,098 ​ ​ ​ ​ ​ 1 ​ ​ ​ ​ ​ 37 ​ ​ ​ ​ ​ 2,221 ​ ​
Production
​ ​ ​ ​ (255,597) ​ ​ ​ ​ ​ (5,200) ​ ​ ​ ​ ​ (1,554) ​ ​ ​ ​ ​ (49,354) ​ ​
Purchase of reserves in place(b)
​ ​ ​ ​ 281,345 ​ ​ ​ ​ ​ 6,356 ​ ​ ​ ​ ​ 1,927 ​ ​ ​ ​ ​ 55,174 ​ ​
Sales of reserves in place(c)
​ ​ ​ ​ (4,968) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (324) ​ ​ ​ ​ ​ (1,152) ​ ​
December 31, 2022
​ ​ ​ ​ 4,349,611 ​ ​ ​ ​ ​ 101,931 ​ ​ ​ ​ ​ 14,830 ​ ​ ​ ​ ​ 841,696 ​ ​
​
(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 the COVID-19 pandemic lows driving a net upward revision of 90,251 MBoe. During 2022, commodity market pricing was volatile and increased significantly due to the war between Russia and Ukraine as well as other geopolitical factors. These factors primarily drove a net upward revision of 64,344 MBoe due to changes in pricing that impacted well economics. These increases were then offset in part by a 1,042 MBoe downward revision for changes in timing.
​
(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,
​
 
F-67
 
and Tapstone acquisitions. During 2022, purchases of reserves in place were primarily related to the East Texas Assets and ConocoPhillips acquisitions. Refer to Note 5 for additional information about acquisitions.
(c)
During 2020 sales of reserves were primarily attributable to the divestitures of non-core assets. During 2021 and 2022 sales of reserves in place were primarily related to the divestitures of non-core assets. Refer to Note 5 for additional information about divestitures.
​
​ ​ ​
Natural Gas
(MMcf)
​ ​
NGLs
(MBbls)
​ ​
Oil
(MBbls)
​ ​
Total
(MBoe)
​
Total proved reserves as of: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
December 31, 2020
​ ​ ​ ​ 2,860,792 ​ ​ ​ ​ ​ 60,206 ​ ​ ​ ​ ​ 4,760 ​ ​ ​ ​ ​ 541,765 ​ ​
December 31, 2021
​ ​ ​ ​ 4,009,037 ​ ​ ​ ​ ​ 89,080 ​ ​ ​ ​ ​ 14,252 ​ ​ ​ ​ ​ 771,505 ​ ​
December 31, 2022
​ ​ ​ ​ 4,349,611 ​ ​ ​ ​ ​ 101,931 ​ ​ ​ ​ ​ 14,830 ​ ​ ​ ​ ​ 841,696 ​ ​
Total proved developed reserves as of: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
December 31, 2020
​ ​ ​ ​ 2,860,792 ​ ​ ​ ​ ​ 60,206 ​ ​ ​ ​ ​ 4,760 ​ ​ ​ ​ ​ 541,765 ​ ​
December 31, 2021
​ ​ ​ ​ 4,008,160 ​ ​ ​ ​ ​ 89,071 ​ ​ ​ ​ ​ 13,823 ​ ​ ​ ​ ​ 770,921 ​ ​
December 31, 2022
​ ​ ​ ​ 4,340,779 ​ ​ ​ ​ ​ 101,931 ​ ​ ​ ​ ​ 14,830 ​ ​ ​ ​ ​ 840,224 ​ ​
Total proved undeveloped reserves as of: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
December 31, 2020
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
December 31, 2021
​ ​ ​ ​ 877 ​ ​ ​ ​ ​ 9 ​ ​ ​ ​ ​ 429 ​ ​ ​ ​ ​ 584 ​ ​
December 31, 2022
​ ​ ​ ​ 8,832 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,472 ​ ​
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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Proved properties
​ ​ ​ $ 3,062,463 ​ ​ ​ ​ $ 2,866,353 ​ ​ ​ ​ $ 1,968,557 ​ ​
Unproved properties
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Total capitalized costs
​ ​ ​ ​ 3,062,463 ​ ​ ​ ​ ​ 2,866,353 ​ ​ ​ ​ ​ 1,968,557 ​ ​
Less: Accumulated depreciation, depletion and amortization
​ ​ ​ ​ (506,655) ​ ​ ​ ​ ​ (336,275) ​ ​ ​ ​ ​ (213,472) ​ ​
Net capitalized costs
​ ​ ​ $ 2,555,808 ​ ​ ​ ​ $ 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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Proved properties
​ ​ ​ $ 260,817 ​ ​ ​ ​ $ 718,353 ​ ​ ​ ​ $ 201,228 ​ ​
Unproved properties
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Total property acquisition costs
​ ​ ​ ​ 260,817 ​ ​ ​ ​ ​ 718,353 ​ ​ ​ ​ ​ 201,228 ​ ​
Total development costs
​ ​ ​ ​ 19,670 ​ ​ ​ ​ ​ 1,464 ​ ​ ​ ​ ​ — ​ ​
Total exploration costs
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Capitalized interest
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Total costs
​ ​ ​ $ 280,487 ​ ​ ​ ​ $ 719,817 ​ ​ ​ ​ $ 201,228 ​ ​
 
F-68
 
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:
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Natural gas (Mcf)
​ ​ ​ $ 6.29 ​ ​ ​ ​ $ 3.26 ​ ​ ​ ​ $ 1.89 ​ ​
NGLs (Bbls)
​ ​ ​ $ 43.68 ​ ​ ​ ​ $ 29.19 ​ ​ ​ ​ $ 5.01 ​ ​
Oil (Bbls)
​ ​ ​ $ 94.01 ​ ​ ​ ​ $ 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,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Future cash inflows
​ ​ ​ $ 32,155,117 ​ ​ ​ ​ $ 16,283,927 ​ ​ ​ ​ $ 5,885,765 ​ ​
Future production costs
​ ​ ​ ​ (8,923,660) ​ ​ ​ ​ ​ (5,773,240) ​ ​ ​ ​ ​ (2,981,059) ​ ​
Future development costs(a)
​ ​ ​ ​ (1,902,297) ​ ​ ​ ​ ​ (1,818,190) ​ ​ ​ ​ ​ (1,570,606) ​ ​
Future income tax expense
​ ​ ​ ​ (5,001,823) ​ ​ ​ ​ ​ (1,644,625) ​ ​ ​ ​ ​ (167,058) ​ ​
Future net cash flows
​ ​ ​ ​ 16,327,337 ​ ​ ​ ​ ​ 7,047,872 ​ ​ ​ ​ ​ 1,167,042 ​ ​
10% annual discount for estimated timing of cash flows
​ ​ ​ ​ (9,584,237) ​ ​ ​ ​ ​ (3,714,781) ​ ​ ​ ​ ​ (161,735) ​ ​
Standardized Measure
​ ​ ​ $ 6,743,100 ​ ​ ​ ​ $ 3,333,091 ​ ​ ​ ​ $ 1,005,307 ​ ​
​
(a)
Includes $1,698,105, $1,615,461 and $1,570,606 in plugging and abandonment costs for the years ended December 31, 2022, 2021 and 2020, respectively.
​
 
F-69
 
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.
Changes in the Standardized Measure were as follows:
​ ​ ​
December 31,
2022
​ ​
December 31,
2021
​ ​
December 31,
2020
​
Standardized Measure, beginning of year
​ ​ ​ $ 3,333,091 ​ ​ ​ ​ $ 1,005,307 ​ ​ ​ ​ $ 1,345,964 ​ ​
Sales and transfers of natural gas and oil produced, net of production costs
​ ​ ​ ​ (1,498,272) ​ ​ ​ ​ ​ (742,375) ​ ​ ​ ​ ​ (230,514) ​ ​
Net changes in prices and production costs
​ ​ ​ ​ 5,137,373 ​ ​ ​ ​ ​ 2,411,163 ​ ​ ​ ​ ​ (576,664) ​ ​
Extensions, discoveries, and other additions, net of future production and development costs
​ ​ ​ ​ 28,038 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Acquisition of reserves in place
​ ​ ​ ​ 555,773 ​ ​ ​ ​ ​ 980,837 ​ ​ ​ ​ ​ 213,210 ​ ​
Divestiture of reserves in place
​ ​ ​ ​ (8,303) ​ ​ ​ ​ ​ (145,434) ​ ​ ​ ​ ​ (2,623) ​ ​
Revisions of previous quantity estimates
​ ​ ​ ​ 702,585 ​ ​ ​ ​ ​ 609,100 ​ ​ ​ ​ ​ (215,079) ​ ​
Net change in income taxes
​ ​ ​ ​ (1,378,438) ​ ​ ​ ​ ​ (622,314) ​ ​ ​ ​ ​ 151,355 ​ ​
Changes in estimated future development costs
​ ​ ​ ​ 22,085 ​ ​ ​ ​ ​ (5,612) ​ ​ ​ ​ ​ 138,665 ​ ​
Previously estimated development costs incurred during the year
​ ​ ​ ​ 7,711 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Changes in production rates (timing) and other
​ ​ ​ ​ (562,245) ​ ​ ​ ​ ​ (266,273) ​ ​ ​ ​ ​ 23,100 ​ ​
Accretion of discount
​ ​ ​ ​ 403,702 ​ ​ ​ ​ ​ 108,692 ​ ​ ​ ​ ​ 157,893 ​ ​
Standardized Measure, end of year
​ ​ ​ $ 6,743,100 ​ ​ ​ ​ $ 3,333,091 ​ ​ ​ ​ $ 1,005,307 ​ ​
 
F-70
 
 
F-71
 
Condensed Consolidated Statement of Comprehensive Income
(Unaudited) (Amounts in thousands, except per share and per unit data)
​ ​ ​ ​ ​ ​
Six Months Ended
​
​ ​ ​
Notes
​ ​
June 30, 2023
​ ​
June 30, 2022
​
Revenue
​ ​
5
​ ​ ​ $ 487,305 ​ ​ ​ ​ $ 933,528 ​ ​
Operating expense
​ ​
6
​ ​ ​ ​ (227,299) ​ ​ ​ ​ ​ (206,357) ​ ​
Depreciation, depletion and amortization
​ ​
6
​ ​ ​ ​ (115,036) ​ ​ ​ ​ ​ (118,480) ​ ​
Gross profit
​ ​ ​ ​ ​ ​ $ 144,970 ​ ​ ​ ​ $ 608,691 ​ ​
General and administrative expense
​ ​
6
​ ​ ​ ​ (55,156) ​ ​ ​ ​ ​ (114,282) ​ ​
Gain (loss) on natural gas and oil property and equipment
​ ​ ​ ​ ​ ​ ​ 7,729 ​ ​ ​ ​ ​ 1,050 ​ ​
Gain (loss) on derivative financial instruments
​ ​
7
​ ​ ​ ​ 812,113 ​ ​ ​ ​ ​ (1,673,841) ​ ​
Gain on bargain purchases
​ ​
4
​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,249 ​ ​
Operating profit (loss)
​ ​ ​ ​ ​ ​ $ 909,656 ​ ​ ​ ​ $ (1,177,133) ​ ​
Finance costs
​ ​
11
​ ​ ​ ​ (67,736) ​ ​ ​ ​ ​ (39,162) ​ ​
Accretion of asset retirement obligation
​ ​
10
​ ​ ​ ​ (13,991) ​ ​ ​ ​ ​ (14,003) ​ ​
Other income (expense)
​ ​ ​ ​ ​ ​ ​ 327 ​ ​ ​ ​ ​ 171 ​ ​
Income (loss) before taxation
​ ​ ​ ​ ​ ​ $ 828,256 ​ ​ ​ ​ $ (1,230,127) ​ ​
Income tax benefit (expense)
​ ​ ​ ​ ​ ​ ​ (197,324) ​ ​ ​ ​ ​ 294,877 ​ ​
Net income (loss)
​ ​ ​ ​ ​ ​ $ 630,932 ​ ​ ​ ​ $ (935,250) ​ ​
Other comprehensive income (loss)
​ ​ ​ ​ ​ ​ ​ (88) ​ ​ ​ ​ ​ 132 ​ ​
Total comprehensive income (loss)
​ ​ ​ ​ ​ ​ $ 630,844 ​ ​ ​ ​ $ (935,118) ​ ​
Net income (loss) attributable to: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Diversified Energy Company PLC
​ ​ ​ ​ ​ ​ $ 629,985 ​ ​ ​ ​ $ (937,412) ​ ​
Non-controlling interest
​ ​ ​ ​ ​ ​ ​ 947 ​ ​ ​ ​ ​ 2,162 ​ ​
Net income (loss)
​ ​ ​ ​ ​ ​ $ 630,932 ​ ​ ​ ​ $ (935,250) ​ ​
Earnings (loss) per share attributable to Diversified Energy Company PLC
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Earnings (loss) per share – basic
​ ​ ​ ​ ​ ​ $ 0.68 ​ ​ ​ ​ $ (1.10) ​ ​
Earnings (loss) per share – diluted
​ ​ ​ ​ ​ ​ $ 0.67 ​ ​ ​ ​ $ (1.10) ​ ​
Weighted average shares outstanding – basic
​ ​ ​ ​ ​ ​ ​ 926,066 ​ ​ ​ ​ ​ 849,621 ​ ​
Weighted average shares outstanding – diluted
​ ​ ​ ​ ​ ​ ​ 937,838 ​ ​ ​ ​ ​ 849,621 ​ ​
The notes are an integral part of the Interim Condensed Consolidated Financial Statements.
F-72
 
Condensed Consolidated Statement of Financial Position
(Unaudited) (Amounts in thousands, except per share and per unit data)
​ ​ ​
Notes
​ ​
June 30, 2023
​ ​
December 31, 2022
​
ASSETS ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Non-current assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Natural gas and oil properties, net
​ ​ ​ ​ ​ ​ $ 2,690,050 ​ ​ ​ ​ $ 2,555,808 ​ ​
Property, plant and equipment, net
​ ​ ​ ​ ​ ​ ​ 465,118 ​ ​ ​ ​ ​ 462,860 ​ ​
Intangible assets
​ ​ ​ ​ ​ ​ ​ 20,798 ​ ​ ​ ​ ​ 21,098 ​ ​
Restricted cash
​ ​
3
​ ​ ​ ​ 32,402 ​ ​ ​ ​ ​ 47,497 ​ ​
Derivative financial instruments
​ ​
7
​ ​ ​ ​ 35,541 ​ ​ ​ ​ ​ 13,936 ​ ​
Deferred tax assets
​ ​ ​ ​ ​ ​ ​ 176,709 ​ ​ ​ ​ ​ 371,156 ​ ​
Other non-current assets
​ ​ ​ ​ ​ ​ ​ 3,678 ​ ​ ​ ​ ​ 4,351 ​ ​
Total non-current assets
​ ​ ​ ​ ​ ​ $ 3,424,296 ​ ​ ​ ​ $ 3,476,706 ​ ​
Current assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Trade receivables, net
​ ​ ​ ​ ​ ​ $ 195,038 ​ ​ ​ ​ $ 296,781 ​ ​
Cash and cash equivalents
​ ​
3
​ ​ ​ ​ 4,208 ​ ​ ​ ​ ​ 7,329 ​ ​
Restricted cash
​ ​
3
​ ​ ​ ​ 8,786 ​ ​ ​ ​ ​ 7,891 ​ ​
Derivative financial instruments
​ ​
7
​ ​ ​ ​ 114,695 ​ ​ ​ ​ ​ 27,739 ​ ​
Other current assets
​ ​ ​ ​ ​ ​ ​ 15,982 ​ ​ ​ ​ ​ 14,482 ​ ​
Total current assets
​ ​ ​ ​ ​ ​ $ 338,709 ​ ​ ​ ​ $ 354,222 ​ ​
Total assets
​ ​ ​ ​ ​ ​ $ 3,763,005 ​ ​ ​ ​ $ 3,830,928 ​ ​
EQUITY AND LIABILITIES ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Shareholders’ equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Share capital
​ ​ ​ ​ ​ ​ $ 13,056 ​ ​ ​ ​ $ 11,503 ​ ​
Share premium
​ ​ ​ ​ ​ ​ ​ 1,208,192 ​ ​ ​ ​ ​ 1,052,959 ​ ​
Treasury reserve
​ ​ ​ ​ ​ ​ ​ (92,811) ​ ​ ​ ​ ​ (100,828) ​ ​
Share based payment and other reserves
​ ​ ​ ​ ​ ​ ​ 9,620 ​ ​ ​ ​ ​ 17,650 ​ ​
Retained earnings (accumulated deficit)
​ ​ ​ ​ ​ ​ ​ (590,109) ​ ​ ​ ​ ​ (1,133,972) ​ ​
Equity attributable to owners of the parent:
​ ​ ​ ​ ​ ​ $ 547,948 ​ ​ ​ ​ $ (152,688) ​ ​
Non-controlling interests
​ ​
4
​ ​ ​ ​ 13,050 ​ ​ ​ ​ ​ 14,964 ​ ​
Total equity
​ ​ ​ ​ ​ ​ $ 560,998 ​ ​ ​ ​ $ (137,724) ​ ​
Non-current liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Asset retirement obligations
​ ​
10
​ ​ ​ $ 448,465 ​ ​ ​ ​ $ 452,554 ​ ​
Leases
​ ​ ​ ​ ​ ​ ​ 22,663 ​ ​ ​ ​ ​ 19,569 ​ ​
Borrowings
​ ​
11
​ ​ ​ ​ 1,272,790 ​ ​ ​ ​ ​ 1,169,233 ​ ​
Deferred tax liability
​ ​ ​ ​ ​ ​ ​ 11,228 ​ ​ ​ ​ ​ 12,490 ​ ​
Derivative financial instruments
​ ​
7
​ ​ ​ ​ 731,093 ​ ​ ​ ​ ​ 1,177,801 ​ ​
Other non-current liabilities
​ ​
12
​ ​ ​ ​ 2,687 ​ ​ ​ ​ ​ 5,375 ​ ​
Total non-current liabilities
​ ​ ​ ​ ​ ​ $ 2,488,926 ​ ​ ​ ​ $ 2,837,022 ​ ​
Current liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Trade and other payables
​ ​ ​ ​ ​ ​ $ 69,744 ​ ​ ​ ​ $ 93,764 ​ ​
Leases
​ ​ ​ ​ ​ ​ ​ 10,645 ​ ​ ​ ​ ​ 9,293 ​ ​
Borrowings
​ ​
11
​ ​ ​ ​ 231,819 ​ ​ ​ ​ ​ 271,096 ​ ​
Derivative financial instruments
​ ​
7
​ ​ ​ ​ 98,172 ​ ​ ​ ​ ​ 293,840 ​ ​
Other current liabilities
​ ​
12
​ ​ ​ ​ 302,701 ​ ​ ​ ​ ​ 463,637 ​ ​
Total current liabilities
​ ​ ​ ​ ​ ​ $ 713,081 ​ ​ ​ ​ $ 1,131,630 ​ ​
Total liabilities
​ ​ ​ ​ ​ ​ $ 3,202,007 ​ ​ ​ ​ $ 3,968,652 ​ ​
Total equity and liabilities
​ ​ ​ ​ ​ ​ $ 3,763,005 ​ ​ ​ ​ $ 3,830,928 ​ ​
The Interim Condensed Consolidated Financial Statements were approved and authorized for issue by the Board on September 1, 2023 and were signed on its behalf by:
[MISSING IMAGE: sg_davidejohnson-bw.jpg]
DAVID E. JOHNSON
Chairman of the Board
September 1, 2023
The notes are an integral part of the Interim Condensed Consolidated Financial Statements.
F-73
 
Condensed Consolidated Statement of Changes in Equity
(Unaudited) (Amounts in thousands, except per share and per unit data)
​ ​ ​
Notes
​ ​
Share
Capital
​ ​
Share
Premium
​ ​
Treasury
Reserve
​ ​
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 January 1, 2023
​ ​ ​ ​ ​ ​ $ 11,503 ​ ​ ​ ​ $ 1,052,959 ​ ​ ​ ​ $ (100,828) ​ ​ ​ ​ $ 17,650 ​ ​ ​ ​ $ (1,133,972) ​ ​ ​ ​ $ (152,688) ​ ​ ​ ​ $ 14,964 ​ ​ ​ ​ $ (137,724) ​ ​
Income (loss) after taxation
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 629,985 ​ ​ ​ ​ ​ 629,985 ​ ​ ​ ​ ​ 947 ​ ​ ​ ​ ​ 630,932 ​ ​
Other comprehensive income
(loss)
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (88) ​ ​ ​ ​ ​ (88) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (88) ​ ​
Total comprehensive income (loss)
​ ​ ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​
$
629,897
 ​ ​ ​ ​ $ 629,897 ​ ​ ​ ​ $ 947 ​ ​ ​ ​
$
630,844
 ​ ​
Issuance of share capital (equity placement)
​ ​ ​ ​ ​ ​ ​ 1,555 ​ ​ ​ ​ ​ 155,233 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 156,788 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 156,788 ​ ​
Issuance of share capital (equity compensation)
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 198 ​ ​ ​ ​ ​ (2,005) ​ ​ ​ ​ ​ (1,807) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (1,807) ​ ​
Issuance of EBT shares (equity compensation)
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 8,230 ​ ​ ​ ​ ​ (8,230) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares (share buyback program)
​ ​ ​ ​ ​ ​ ​ (2) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (213) ​ ​ ​ ​ ​ 2 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (213) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (213) ​ ​
Dividends
​ ​
9
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (84,029) ​ ​ ​ ​ ​ (84,029) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (84,029) ​ ​
Distributions to non-controlling interest owners
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (2,861) ​ ​ ​ ​ ​ (2,861) ​ ​
Transactions with shareholders
​ ​ ​ ​ ​ ​ $ 1,553 ​ ​ ​ ​ $ 155,233 ​ ​ ​ ​ $ 8,017 ​ ​ ​ ​ $ (8,030) ​ ​ ​ ​ $ (86,034) ​ ​ ​ ​ $ 70,739 ​ ​ ​ ​ $ (2,861) ​ ​ ​ ​ $ 67,878 ​ ​
Balance as of June 30, 2023
​ ​ ​ ​ ​ ​ $ 13,056 ​ ​ ​ ​ $ 1,208,192 ​ ​ ​ ​ $ (92,811) ​ ​ ​ ​ $ 9,620 ​ ​ ​ ​ $ (590,109) ​ ​ ​ ​ $ 547,948 ​ ​ ​ ​ $ 13,050 ​ ​ ​ ​ $ 560,998 ​ ​
​ ​ ​
Notes
​ ​
Share
Capital
​ ​
Share
Premium
​ ​
Treasury
Reserve
​ ​
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 January 1, 2022
​ ​ ​ ​ ​ ​ $ 11,571 ​ ​ ​ ​ $ 1,052,959 ​ ​ ​ ​ $ (68,537) ​ ​ ​ ​ $ 14,156 ​ ​ ​ ​ $ (362,740) ​ ​ ​ ​ $ 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)
​ ​
Issuance of share capital (settlement of
warrants)
​ ​ ​ ​ ​ ​ ​ 2 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2 ​ ​
Issuance of share capital (equity compensation)
​ ​ ​ ​ ​ ​ ​ 7 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 3,375 ​ ​ ​ ​ ​ (1,517) ​ ​ ​ ​ ​ 1,865 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,865 ​ ​
Repurchase of shares (EBT)
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (9,718) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (9,718) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (9,718) ​ ​
Dividends
​ ​
9
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (72,275) ​ ​ ​ ​ ​ (72,275) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (72,275) ​ ​
Distributions to non-controlling interest owners
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (2,776) ​ ​ ​ ​ ​ (2,776) ​ ​
Cancellation of warrants
​ ​ ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (14) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (14) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (14) ​ ​
Transactions with shareholders
​ ​ ​ ​ ​ ​ $ 9 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (9,718) ​ ​ ​ ​ $ 3,361 ​ ​ ​ ​ $ (73,792) ​ ​ ​ ​ $ (80,140) ​ ​ ​ ​ $ (2,776) ​ ​ ​ ​ $ (82,916) ​ ​
Balance as of June 30, 2022
​ ​ ​ ​ ​ ​ $ 11,580 ​ ​ ​ ​ $ 1,052,959 ​ ​ ​ ​ $ (78,255) ​ ​ ​ ​ $ 17,517 ​ ​ ​ ​ $ (1,373,812) ​ ​ ​ ​ $ (370,011) ​ ​ ​ ​ $ 15,927 ​ ​ ​ ​ $ (354,084) ​ ​
The notes are an integral part of the Interim Condensed Consolidated Financial Statements.
F-74
 
Condensed Consolidated Statement of Cash Flows
(Unaudited) (Amounts in thousands, except per share and per unit data)
​ ​ ​ ​ ​ ​
Six Months Ended
​
​ ​ ​
Notes
​ ​
June 30, 2023
​ ​
June 30, 2022
​
Cash flows from operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Income (loss) after taxation
​ ​ ​ ​ ​ ​ $ 630,932 ​ ​ ​ ​ $ (935,250) ​ ​
Cash flows from operations reconciliation: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Depreciation, depletion and amortization
​ ​
6
​ ​ ​ ​ 115,036 ​ ​ ​ ​ ​ 118,480 ​ ​
Accretion of asset retirement obligations
​ ​
10
​ ​ ​ ​ 13,991 ​ ​ ​ ​ ​ 14,003 ​ ​
Income tax (benefit) expense
​ ​ ​ ​ ​ ​ ​ 197,324 ​ ​ ​ ​ ​ (294,877) ​ ​
(Gain) loss on fair value adjustments of unsettled financial instruments
​ ​
7
​ ​ ​ ​ (760,933) ​ ​ ​ ​ ​ 1,205,938 ​ ​
Asset retirement costs
​ ​
10
​ ​ ​ ​ (2,077) ​ ​ ​ ​ ​ (1,582) ​ ​
(Gain) loss on natural gas and oil properties and equipment
​ ​ ​ ​ ​ ​ ​ (7,729) ​ ​ ​ ​ ​ 515 ​ ​
Gain on bargain purchases
​ ​
4
​ ​ ​ ​ — ​ ​ ​ ​ ​ (1,249) ​ ​
Finance costs
​ ​
11
​ ​ ​ ​ 67,736 ​ ​ ​ ​ ​ 39,162 ​ ​
Hedge modifications
​ ​
7
​ ​ ​ ​ 17,446 ​ ​ ​ ​ ​ (6,833) ​ ​
Non-cash equity compensation
​ ​
6
​ ​ ​ ​ 4,417 ​ ​ ​ ​ ​ 4,069 ​ ​
Working capital adjustments: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Change in trade receivables and other current assets
​ ​ ​ ​ ​ ​ ​ 93,968 ​ ​ ​ ​ ​ (74,672) ​ ​
Change in other non-current assets
​ ​ ​ ​ ​ ​ ​ (259) ​ ​ ​ ​ ​ (1,632) ​ ​
Change in trade and other payables and other current liabilities
​ ​ ​ ​ ​ ​ ​ (189,636) ​ ​ ​ ​ ​ 177,382 ​ ​
Change in other non-current liabilities
​ ​ ​ ​ ​ ​ ​ (5,733) ​ ​ ​ ​ ​ (8,612) ​ ​
Cash generated from operations
​ ​ ​ ​ ​ ​ $ 174,483 ​ ​ ​ ​ $ 234,842 ​ ​
Cash paid for income taxes
​ ​ ​ ​ ​ ​ ​ (1,917) ​ ​ ​ ​ ​ (29,855) ​ ​
Net cash provided by operating activities
​ ​ ​ ​ ​ ​ $ 172,566 ​ ​ ​ ​ $ 204,987 ​ ​
Cash flows from investing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Consideration for business acquisitions, net of cash acquired
​ ​
4
​ ​ ​ $ — ​ ​ ​ ​ $ (12,274) ​ ​
Consideration for asset acquisitions
​ ​
4
​ ​ ​ ​ (262,329) ​ ​ ​ ​ ​ (51,550) ​ ​
Proceeds from divestitures
​ ​
4
​ ​ ​ ​ 37,503 ​ ​ ​ ​ ​ — ​ ​
Expenditures on natural gas and oil properties and equipment
​ ​ ​ ​ ​ ​ ​ (32,332) ​ ​ ​ ​ ​ (44,539) ​ ​
Proceeds on disposals of natural gas and oil properties and equipment
​ ​ ​ ​ ​ ​ ​ 8,661 ​ ​ ​ ​ ​ 6,052 ​ ​
Contingent consideration payments
​ ​
13
​ ​ ​ ​ (1,520) ​ ​ ​ ​ ​ (19,807) ​ ​
Net cash used in investing activities
​ ​ ​ ​ ​ ​ $ (250,017) ​ ​ ​ ​ $ (122,118) ​ ​
Cash flows from financing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Repayment of borrowings
​ ​
11
​ ​ ​ $ (782,990) ​ ​ ​ ​ $ (1,392,883) ​ ​
Proceeds from borrowings
​ ​
11
​ ​ ​ ​ 840,230 ​ ​ ​ ​ ​ 1,730,200 ​ ​
Cash paid for interest
​ ​
11
​ ​ ​ ​ (59,415) ​ ​ ​ ​ ​ (32,605) ​ ​
Debt issuance cost
​ ​
11
​ ​ ​ ​ (1,730) ​ ​ ​ ​ ​ (24,579) ​ ​
(Increase) decrease in restricted cash(a)
​ ​ ​ ​ ​ ​ ​ 14,200 ​ ​ ​ ​ ​ (25,103) ​ ​
Hedge modifications associated with ABS Notes
​ ​
7, 11
​ ​ ​ ​ — ​ ​ ​ ​ ​ (73,073) ​ ​
Proceeds from equity issuance, net
​ ​
8
​ ​ ​ ​ 156,788 ​ ​ ​ ​ ​ — ​ ​
Principal element of lease payments
​ ​ ​ ​ ​ ​ ​ (5,757) ​ ​ ​ ​ ​ (5,273) ​ ​
Dividends to shareholders
​ ​
9
​ ​ ​ ​ (84,029) ​ ​ ​ ​ ​ (72,275) ​ ​
Distributions to non-controlling interest owners
​ ​ ​ ​ ​ ​ ​ (2,861) ​ ​ ​ ​ ​ (2,776) ​ ​
Repurchase of shares by the EBT
​ ​
8
​ ​ ​ ​ — ​ ​ ​ ​ ​ (9,718) ​ ​
Repurchase of shares
​ ​
8
​ ​ ​ ​ (106) ​ ​ ​ ​ ​ — ​ ​
Net cash provided by (used in) financing activities
​ ​ ​ ​ ​ ​ $ 74,330 ​ ​ ​ ​ $ 91,915 ​ ​
Net change in cash and cash equivalents
​ ​ ​ ​ ​ ​ ​ (3,121) ​ ​ ​ ​ ​ 174,784 ​ ​
Cash and cash equivalents, beginning of period
​ ​ ​ ​ ​ ​ ​ 7,329 ​ ​ ​ ​ ​ 12,558 ​ ​
Cash and cash equivalents, end of period
​ ​ ​ ​ ​ ​ $ 4,208 ​ ​ ​ ​ $ 187,342 ​ ​
​
(a)
Refer to Note 2 for information regarding prior period reclassifications.
​
The notes are an integral part of the Interim Condensed Consolidated Financial Statements.
F-75
 
Index to the Notes to the Consolidated Financial Statements
​ ​ ​
Page
​
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​ ​ ​ ​ F-77 ​ ​
​ ​ ​ ​ F-79 ​ ​
​ ​ ​ ​ F-80 ​ ​
​ ​ ​ ​ F-81 ​ ​
​ ​ ​ ​ F-82 ​ ​
​ ​ ​ ​ F-83 ​ ​
​ ​ ​ ​ F-89 ​ ​
​ ​ ​ ​ F-90 ​ ​
​ ​ ​ ​ F-91 ​ ​
​ ​ ​ ​ F-92 ​ ​
​ ​ ​ ​ F-99 ​ ​
​ ​ ​ ​ F-99 ​ ​
​ ​ ​ ​ F-101 ​ ​
​ ​ ​ ​ F-101 ​ ​
​ ​ ​ ​ F-102 ​ ​
 
F-76
 
Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)
NOTE 1 — GENERAL INFORMATION
Diversified Energy Company PLC (the “Parent”) and its wholly owned subsidiaries (together the “Company”) is an independent energy company engaged in the production, marketing and transportation of primarily natural gas related to its synergistic U.S. onshore upstream and midstream assets. The Company’s assets are located within the Central Region and Appalachian Basin of the U.S.
The Company 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 Phoenix House, 1 Station Hill, Reading, Berkshire, RG1 1NB, UK.
In May 2020, the Company’s shares were admitted to trading on the LSE’s Main Market for listed securities. The Company’s shares are listed on the LSE under the ticker “DEC.”
NOTE 2 — BASIS OF PREPARATION
Basis of Preparation
The Company’s unaudited interim condensed consolidated financial statements for the six months ended June 30, 2023 (the “Interim Condensed Consolidated Financial Statements”) have been prepared in accordance with International Accounting Standard 34, ‘Interim Financial Reporting’ (“IAS 34”) as issued by the International Accounting Standards Board (the “IASB”).
The Interim Condensed Consolidated 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, 2022, which were prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the 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 Interim Condensed Consolidated Financial Statements are presented in U.S. 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 U.S. 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’s subsidiary 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 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.
 
F-77
 
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.
In accordance with IFRS and UK-adopted IFRS the Company establishes segments on the basis by which those components of the Company are evaluated regularly by the chief executive officer, the Company’s chief operating decision maker, when deciding how to allocate resources and in assessing performance. When evaluating performance as well as when acquiring and managing assets the chief operating decision maker does so in a consolidated and complementary fashion to vertically integrate and improve margins. 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 U.S.
Going Concern
The Interim Condensed Consolidated Financial Statements have been prepared on the going concern basis of accounting. The Directors closely monitor and carefully manage the Company’s Liquidity risk. The Company’s 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. In assessing the appropriateness of the going concern assumption over the next twelve months, management have stress tested the Company’s most recent financial projections to incorporate a range of potential future outcomes by considering the Company’s principal risks, potential downside pressures on commodity prices, long-term demand and availability of loan facility; management has also considered cash preservation measures, including reduced capital expenditure and shareholder distributions. This assessment confirmed that the Company has adequate cash and other liquid resources to enable it to meet its obligations as they fall due in order to continue its operations over the twelve months from the issuance date of these Interim Condensed Consolidated Financial Statements. Therefore, the Directors consider it appropriate to continue to adopt the going concern basis of accounting in preparing these unaudited Interim Condensed Consolidated Financial Statements.
Prior Period Reclassifications
Reclassifications in the Consolidated Statement of Changes in Equity
To provide additional transparency into equity activity, the Company has reclassified certain amounts in its prior year Consolidated Statement of Changes in Equity to conform to its current period presentation. These changes in reclassification do not affect total comprehensive income previously reported in the Consolidated Statement of Changes in Equity.
The Company reclassified $68,537 in “Repurchases of shares” from “Retained Earnings (Accumulated Deficit)” to “Treasury Reserve” in the accompanying Consolidated Statement of Changes in Equity as of June 30, 2023.
Reclassifications in the Consolidated Statement of Cash Flows
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 net cash provided by operating activities previously reported in the Consolidated Statement of Cash Flows.
The Company reclassified $24,099 in “Change in other current assets” to “Change in trade receivables and other current assets” and $205,289 in “Change in other current and non-current liabilities” to “Change in trade and other payables and other current liabilities” in the accompanying Consolidated Statement of
 
F-78
 
Cash Flows for the six months ended June 30, 2023. The Company also reclassified $25,103 in “(Increase) decrease in restricted cash” from “Cash flows from investing activities” to “Cash flows from financing activities” in the accompanying Consolidated Statement of Cash Flows for the six months ended June 30, 2022.
Basis of Consolidation
The Interim Condensed Consolidated Financial Statements for the six months ended June 30, 2023 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 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
​
>
Sooner State Joint ABS Holdings LLC(a)
​
>
Diversified ABS Phase VI Holdings LLC
​
>
Diversified ABS Phase VI LLC
​
>
Diversified ABS VI Upstream LLC
​
>
Oaktree ABS VI Upstream LLC
​
>
DP RBL Co LLC
​
>
BlueStone Natural Resources II, LLC
​
>
DP Legacy Central LLC
​
>
Diversified Energy Marketing LLC
​
>
DP Tapstone Energy Holdings LLC
​
>
DP Legacy Tapstone LLC
​
>
Giant Land, LLC(b)
​
>
Link Land LLC(n)
​
>
Old Faithful Land LLC(n)
​
>
Riverside Land LLC(n)
​
>
Splendid Land LLC(n)
​
>
Chesapeake Granite Wash Trust(c)
​
>
TGG Cotton Valley Assets, 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
​
>
DGOC Holdings Sub III LLC
​
>
Diversified Energy Group LLC
​
>
Diversified Energy Company LLC
​
>
Next LVL Energy, LLC
​
​
​
(a)
Owned 51.25% by Diversified Energy Company PLC.
​
(b)
Owned 55% by Diversified Energy Company PLC.
​
(c)
Diversified Production, LLC holds 50.8% of the issued and outstanding common shares of Chesapeake Granite Wash Trust.
​
NOTE 3 — SIGNIFICANT ACCOUNTING POLICIES
The preparation of the Interim Condensed Consolidated Financial Statements in compliance with IAS 34 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 judgments 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, 2022.
 
F-79
 
When determining the income tax benefit (expense) recognized during interim periods management estimates the weighted average effective annual income tax rate expected for the full financial year. The estimated average annual tax rate used for the six months ended June 30, 2023 was 23.8%, compared to 24.0% for the six months ended June 30, 2022.
New Standards and Interpretations
Certain new accounting standards and interpretations have been published that are not mandatory for June 30, 2023 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 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 that complement the Company’s acquisition criteria of being long life, low-decline assets that strategically complement the Company’s existing asset base.
2023 Acquisitions
Tanos Energy Holdings II, LLC (“Tanos II”) Asset Acquisition
On March 1, 2023 the Company acquired certain upstream assets and related infrastructure in the Central Region from Tanos II. 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 $262,329, inclusive of transaction costs of $936 and customary purchase price adjustments. The Company funded the purchase with proceeds from the February 2023 equity raise, cash on hand and existing availability on the Credit Facility for which the borrowing base was upsized concurrent to the closing of the Tanos II transaction. Refer to Notes 8 and 11 for additional information regarding the Company’s share capital and borrowings. In the period from its acquisition to June 30, 2023 the Tanos II assets increased the Company’s revenue by $24,741.
The provisional assets and liabilities assumed were as follows:
​ Consideration paid ​ ​ ​ ​ ​ ​ ​
​
Cash consideration
​ ​ ​ $ 262,329 ​ ​
​
Total consideration
​ ​ ​ $ 262,329 ​ ​
​ Net assets acquired ​ ​ ​ ​ ​ ​ ​
​
Natural gas and oil properties
​ ​ ​ $ 263,056 ​ ​
​
Asset retirement obligations, asset portion
​ ​ ​ ​ 3,250 ​ ​
​
Property, plant and equipment
​ ​ ​ ​ 234 ​ ​
​
Trade receivables, net
​ ​ ​ ​ 1,729 ​ ​
​
Derivative financial instruments, net
​ ​ ​ ​ 7,449 ​ ​
​
Asset retirement obligations, liability portion
​ ​ ​ ​ (3,250) ​ ​
​
Other current liabilities
​ ​ ​ ​ (10,139) ​ ​
​
Net assets acquired
​ ​ ​ $ 262,329 ​ ​
2023 Divestitures
On June 27, 2023, the Company announced the sale of certain non-core, non-operated assets within its Central Region for gross consideration of approximately $37,503. The divested assets were located in Texas and Oklahoma and consisted of non-operated wells and the associated leasehold acreage that was acquired
 
F-80
 
as part of the ConocoPhillips Asset Acquisition in September 2022. This sale of non-operated and non-core assets aligns with the Company’s application of the Smarter Asset Management strategy and our strategic focus on operated proved developed producing assets.
During the six months ended June 30, 2023, the Company divested certain other non-core undeveloped acreage across its operating footprint for consideration of approximately $6,000.
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 $47,468, 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. During 2022 purchase accounting was finalized and no measurement period adjustments were recorded.
Other Acquisitions
During the period ended December 31, 2022 the Company acquired three asset retirement companies for an aggregate consideration of $13,949, inclusive of customary purchase price adjustments. The Company will also pay an additional $3,150 in deferred consideration through November 2024. As of June 30, 2023, the Company has paid $1,000 of the deferred consideration. When evaluating these transactions, the Company determined they did not have significant asset concentrations and, as a result, it had acquired identifiable sets of inputs, processes and outputs, and concluded the transactions were business combinations. The expansion in the Company’s internal asset retirement operations brought the total plugging rigs owned and operated by the Company to15 as of December 31, 2022.
On April 1, 2022 the Company acquired certain midstream assets, inclusive of a processing facility, in the Central Region that are contiguous to its existing East Texas assets. The Company paid purchase consideration of $10,139, inclusive of customary purchase price adjustments and transaction costs. When evaluating the transaction, the Company 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 fair value of the net assets acquired was $10,742 generating a bargain purchase gain of $603.
On November 21, 2022 the Company acquired certain midstream assets in the Central Region that are contiguous to its existing East Texas assets. The Company paid purchase consideration of $7,438, inclusive of customary purchase price adjustments and transaction costs. Given the concentration of assets, this transaction was considered an asset acquisition rather than a business combination.
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 17, 2023, the Company announced the sale of certain undeveloped, non-core, net acres within its Central Region for net consideration of approximately $16,060. This sale of undeveloped, non-core assets continues to align with the Company’s strategic initiatives and focus on operated proved developed producing assets.
NOTE 5 — 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 as well as asset retirement and other services to third parties. All revenue was generated in the U.S.
 
F-81
 
The following table reconciles the Company’s revenue for the periods presented:
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30, 2023
​ ​
June 30, 2022
​
Natural gas
​ ​ ​ $ 334,588 ​ ​ ​ ​ $ 727,152 ​ ​
NGLs
​ ​ ​ ​ 67,159 ​ ​ ​ ​ ​ 107,846 ​ ​
Oil
​ ​ ​ ​ 54,294 ​ ​ ​ ​ ​ 78,817 ​ ​
Total commodity revenue
​ ​ ​ $ 456,041 ​ ​ ​ ​ $ 913,815 ​ ​
Midstream
​ ​ ​ ​ 16,662 ​ ​ ​ ​ ​ 16,602 ​ ​
Other(a)
​ ​ ​ ​ 14,602 ​ ​ ​ ​ ​ 3,111 ​ ​
Total revenue
​ ​ ​ $ 487,305 ​ ​ ​ ​ $ 933,528 ​ ​
​
(a)
Includes asset retirement and other revenue.
​
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 six months ended June 30, 2023 and June 30, 2022, no customers individually comprised more than 10% of total revenues.
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, 2023
​ ​
June 30, 2022
​
LOE(a)
​ ​ ​ $ 111,637 ​ ​ ​ ​ $ 81,776 ​ ​
Production taxes(b)
​ ​ ​ ​ 31,307 ​ ​ ​ ​ ​ 33,878 ​ ​
Midstream operating expense(c)
​ ​ ​ ​ 34,391 ​ ​ ​ ​ ​ 33,156 ​ ​
Transportation expense(d)
​ ​ ​ ​ 49,964 ​ ​ ​ ​ ​ 57,547 ​ ​
Total operating expense
​ ​ ​ $ 227,299 ​ ​ ​ ​ $ 206,357 ​ ​
Depreciation and amortization
​ ​ ​ ​ 27,503 ​ ​ ​ ​ ​ 25,251 ​ ​
Depletion
​ ​ ​ ​ 87,533 ​ ​ ​ ​ ​ 93,229 ​ ​
Total depreciation, depletion and amortization
​ ​ ​ $ 115,036 ​ ​ ​ ​ $ 118,480 ​ ​
Employees, administrative costs and professional services(e)
​ ​ ​ ​ 38,497 ​ ​ ​ ​ ​ 36,245 ​ ​
Costs associated with acquisitions(f)
​ ​ ​ ​ 8,866 ​ ​ ​ ​ ​ 6,935 ​ ​
Other adjusting costs(g)
​ ​ ​ ​ 3,376 ​ ​ ​ ​ ​ 67,033 ​ ​
Non-cash equity compensation(h)
​ ​ ​ ​ 4,417 ​ ​ ​ ​ ​ 4,069 ​ ​
Total G&A
​ ​ ​ $ 55,156 ​ ​ ​ ​ $ 114,282 ​ ​
Total expense
​ ​ ​ $ 397,491 ​ ​ ​ ​ $ 439,119 ​ ​
Aggregate remuneration (including Directors):
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Wages and salaries
​ ​ ​ $ 61,135 ​ ​ ​ ​ $ 53,561 ​ ​
Payroll taxes
​ ​ ​ ​ 5,238 ​ ​ ​ ​ ​ 4,881 ​ ​
Benefits
​ ​ ​ ​ 12,560 ​ ​ ​ ​ ​ 11,715 ​ ​
Total employees and benefits expense
​ ​ ​ $ 78,933 ​ ​ ​ ​ $ 70,157 ​ ​
​
(a)
LOE includes costs incurred to maintain producing properties. Such costs include direct and contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.
​
 
F-82
 
(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)
Employees, administrative costs and professional services includes payroll and benefits for the Company’s administrative and corporate staff, costs of maintaining administrative and corporate offices, costs of managing the Company’s production operations, franchise taxes, public company costs, fees for audit and other professional services and legal compliance.
​
(f)
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 the Company pays 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, these costs 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.
​
(g)
Other adjusting costs for the six months ended June 30, 2023 primarily consisted of expenses associated with an unused firm transportation agreement and legal and professional fees related to contemplated transaction. Other adjusting costs for the six months ended June 30, 2022, primarily consisted of $28,345 in contract terminations which will allow the Company to obtain more favorable pricing in the future and $31,099 in costs associated with deal breakage and/or sourcing costs for acquisitions.
​
(h)
Non-cash equity compensation reflects the expense recognition related to share-based compensation provided to certain key members of the management team.
​
NOTE 7 — 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, 2023, 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;
 
F-83
 
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. If the Company sells a put option, the Company pays 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.
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
(MMBtu)
​ ​
Swaps
​ ​
Sold
Puts
​ ​
Purchased
Puts
​ ​
Sold
Calls
​ ​
Basis
Differential
​ ​
Fair Value at
June 30, 2023
​
For the remainder of 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 105,417 ​ ​ ​ ​ $ 3.78 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ 57,677 ​ ​
Two-way Collars
​ ​ ​ ​ 1,377 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.15 ​ ​ ​ ​ ​ 6.51 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,002 ​ ​
Stand-Alone Calls, net(b)
​ ​ ​ ​ 10,755 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.94 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (26,276) ​ ​
Basis Swaps
​ ​ ​ ​ 101,595 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (0.65) ​ ​ ​ ​ ​ 33,044 ​ ​
Total 2023 contracts
​ ​ ​ ​ 219,144 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ 65,447 ​ ​
2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 204,997 ​ ​ ​ ​ $ 3.30 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (85,061) ​ ​
Two-Way Collars
​ ​ ​ ​ 2,560 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.03 ​ ​ ​ ​ ​ 6.25 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1,034 ​ ​
Deferred Premium(c)
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (47,470) ​ ​
Basis Swaps
​ ​ ​ ​ 145,297 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (0.70) ​ ​ ​ ​ ​ (8,021) ​ ​
Total 2024 contracts
​ ​ ​ ​ 352,854 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (139,518) ​ ​
2025 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 166,055 ​ ​ ​ ​ $ 3.26 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (135,636) ​ ​
Deferred Premium(c)
​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (32,108) ​ ​
Basis Swaps
​ ​ ​ ​ 25,550 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (0.21) ​ ​ ​ ​ ​ (424) ​ ​
Total 2025 contracts
​ ​ ​ ​ 191,605 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (168,168) ​ ​
2026 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 111,471 ​ ​ ​ ​ $ 3.18 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (96,168) ​ ​
Stand-Alone Calls
​ ​ ​ ​ 21,900 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.28 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (15,348) ​ ​
Basis Swap
​ ​ ​ ​ 10,950 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (0.21) ​ ​ ​ ​ ​ (948) ​ ​
Total 2026 contracts
​ ​ ​ ​ 144,321 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (112,464) ​ ​
 
F-84
 
​ ​ ​ ​ ​ ​ ​ ​ ​
Weighted Average Price per Mcfe(a)
​ ​ ​ ​ ​ ​ ​
NATURAL GAS CONTRACTS
​ ​
Volume
(MMBtu)
​ ​
Swaps
​ ​
Sold
Puts
​ ​
Purchased
Puts
​ ​
Sold
Calls
​ ​
Basis
Differential
​ ​
Fair Value at
June 30, 2023
​
2027 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 91,004 ​ ​ ​ ​ $ 3.22 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (60,470) ​ ​
Collars
​ ​ ​ ​ 1,414 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.28 ​ ​ ​ ​ ​ 7.17 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 673 ​ ​
Purchased puts
​ ​ ​ ​ 4,906 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.25 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 782 ​ ​
Sold puts
​ ​ ​ ​ 4,906 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (486) ​ ​
2028 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 32,190 ​ ​ ​ ​ $ 2.11 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (44,369) ​ ​
Collars
​ ​ ​ ​ 5,382 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.28 ​ ​ ​ ​ ​ 6.90 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2,795 ​ ​
Purchased puts
​ ​ ​ ​ 54,203 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 3.04 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 21,917 ​ ​
Sold puts
​ ​ ​ ​ 31,585 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (3,592) ​ ​
2029 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 29,190 ​ ​ ​ ​ $ 2.11 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (38,153) ​ ​
Collars
​ ​ ​ ​ 3,726 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 4.28 ​ ​ ​ ​ ​ 7.51 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2,068 ​ ​
Purchased puts
​ ​ ​ ​ 30,066 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.92 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 11,721 ​ ​
Sold puts
​ ​ ​ ​ 30,066 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (3,955) ​ ​
2030 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 5,450 ​ ​ ​ ​ $ 2.03 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (7,965) ​ ​
Purchased puts
​ ​ ​ ​ 14,492 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 2.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 5,710 ​ ​
Sold puts
​ ​ ​ ​ 14,492 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 1.93 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (2,037) ​ ​
Swaptions ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
10/1/2024 – 9/30/2028(d)
​ ​ ​ ​ 14,610 ​ ​ ​ ​ $ 2.91 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (14,072) ​ ​
1/1/2025 – 12/31/2029(e)
​ ​ ​ ​ 36,520 ​ ​ ​ ​ ​ 2.77 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (38,400) ​ ​
4/1/2026 – 3/31/2030(f)
​ ​ ​ ​ 97,277 ​ ​ ​ ​ ​ 2.57 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (138,652) ​ ​
4/1/2030 – 3/31/2032(g)
​ ​ ​ ​ 42,627 ​ ​ ​ ​ ​ 2.57 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ (48,743) ​ ​
Total 2027 – 2032 contracts
​ ​ ​ ​ 544,106 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (355,228) ​ ​
Total natural gas contracts
​ ​ ​ ​ 1,452,030 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (709,931) ​ ​
​
​
(a)
Rates have been converted from Btu to Mcfe using a Btu conversion factor of 1.07.
​
(b)
Inclusive of $21,095 in future cash settlements for deferred premiums.
​
(c)
Future cash settlements for deferred premiums.
​
(d)
Option expires on September 6, 2024.
​
(e)
Option expires on December 23, 2024.
​
(f)
Option expires on March 23, 2026.
​
(g)
Option expires on March 22, 2030.
​
 
F-85
 
​ ​ ​ ​ ​ ​ ​ ​ ​
Weighted Average Price per Bbl
​ ​ ​ ​ ​ ​ ​
NGLs CONTRACTS
​ ​
Volume
(MBbls)
​ ​
Swaps
​ ​
Sold
Calls
​ ​
Fair Value at
June 30, 2023
​
For the remainder of 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 2,273 ​ ​ ​ ​ $ 37.49 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ 20,885 ​ ​
Stand-Alone Calls
​ ​ ​ ​ 184 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 24.78 ​ ​ ​ ​ ​ (427) ​ ​
2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 3,301 ​ ​ ​ ​ $ 37.74 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ 20,317 ​ ​
Stand-Alone Calls
​ ​ ​ ​ 915 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 31.29 ​ ​ ​ ​ ​ (2,658) ​ ​
2025 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 2,143 ​ ​ ​ ​ $ 30.22 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ 1,619 ​ ​
2026 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 1,097 ​ ​ ​ ​ $ 27.68 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (621) ​ ​
Total NGLs contracts
​ ​ ​ ​ 9,913 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ 39,115 ​ ​
​ ​ ​ ​ ​ ​ ​ ​ ​
Weighted Average Price per Bbl
​ ​ ​ ​ ​ ​ ​
OIL CONTRACTS
​ ​
Volume
(MBbls)
​ ​
Swaps
​ ​
Sold
Calls
​ ​
Fair Value at
June 30, 2023
​
For the remainder of 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 448 ​ ​ ​ ​ $ 69.12 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (448) ​ ​
Sold Calls
​ ​ ​ ​ 59 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 53.20 ​ ​ ​ ​ ​ (1,018) ​ ​
2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 431 ​ ​ ​ ​ $ 62.54 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (2,441) ​ ​
Sold Calls
​ ​ ​ ​ 183 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ 70.00 ​ ​ ​ ​ ​ (1,327) ​ ​
2025 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 366 ​ ​ ​ ​ $ 59.01 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (2,165) ​ ​
2026 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 283 ​ ​ ​ ​ $ 59.48 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (899) ​ ​
2027 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Swaps
​ ​ ​ ​ 162 ​ ​ ​ ​ $ 58.60 ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (352) ​ ​
Total oil contracts
​ ​ ​ ​ 1,932 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (8,650) ​ ​
INTEREST
​ ​
Principal Hedged
​ ​
Fixed-Rate
​ ​
Fair Value at
June 30, 2023
​
2023
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
SOFR Interest Rate Swap
​ ​ ​ $ 5,520 ​ ​ ​ ​ ​ 4.15% ​ ​ ​ ​ $ 437 ​ ​
Net fair value of derivative financial instruments as of June 30, 2023
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ (679,029) ​ ​
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 periods presented:
 
F-86
 
Derivative Financial Instruments
​ ​
Consolidated Statement of Financial Position
​ ​
June 30, 2023
​ ​
December 31, 2022
​
Assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Non-current assets
​ ​
Derivative financial instruments
​ ​ ​ $ 35,541 ​ ​ ​ ​ $ 13,936 ​ ​
Current assets
​ ​
Derivative financial instruments
​ ​ ​ ​ 114,695 ​ ​ ​ ​ ​ 27,739 ​ ​
Total assets
​ ​ ​ ​ ​ ​ $ 150,236 ​ ​ ​ ​ $ 41,675 ​ ​
Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Non-current liabilities
​ ​
Derivative financial instruments
​ ​ ​ $ (731,093) ​ ​ ​ ​ $ (1,177,801) ​ ​
Current liabilities
​ ​
Derivative financial instruments
​ ​ ​ ​ (98,172) ​ ​ ​ ​ ​ (293,840) ​ ​
Total liabilities
​ ​ ​ ​ ​ ​ $ (829,265) ​ ​ ​ ​ $ (1,471,641) ​ ​
Net assets (liabilities): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Net assets (liabilities) – non-current
​ ​
Derivative financial instruments
​ ​ ​ $ (695,552) ​ ​ ​ ​ $ (1,163,865) ​ ​
Net assets (liabilities) – current
​ ​
Derivative financial instruments
​ ​ ​ ​ 16,523 ​ ​ ​ ​ ​ (266,101) ​ ​
Total net assets (liabilities)
​ ​ ​ ​ ​ ​ $ (679,029) ​ ​ ​ ​ $ (1,429,966) ​ ​
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 as of the periods indicated:
​ ​ ​
June 30, 2023
​
​ ​ ​
Presented without
Effects of Netting
​ ​
Effects of Netting
​ ​
As Presented with
Effects of Netting
​
Non-current assets
​ ​ ​ $ 123,597 ​ ​ ​ ​ $ (88,056) ​ ​ ​ ​ $ 35,541 ​ ​
Current assets
​ ​ ​ ​ 177,872 ​ ​ ​ ​ ​ (63,177) ​ ​ ​ ​ ​ 114,695 ​ ​
Total assets
​ ​ ​ $ 301,469 ​ ​ ​ ​ $ (151,233) ​ ​ ​ ​ $ 150,236 ​ ​
Non-current liabilities
​ ​ ​ ​ (797,221) ​ ​ ​ ​ ​ 66,128 ​ ​ ​ ​ ​ (731,093) ​ ​
Current liabilities
​ ​ ​ ​ (183,277) ​ ​ ​ ​ ​ 85,105 ​ ​ ​ ​ ​ (98,172) ​ ​
Total liabilities
​ ​ ​ $ (980,498) ​ ​ ​ ​ $ 151,233 ​ ​ ​ ​ $ (829,265) ​ ​
Total net assets (liabilities)
​ ​ ​ $ (679,029) ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (679,029) ​ ​
​ ​ ​
December 31, 2022
​
​ ​ ​
Presented without
Effects of Netting
​ ​
Effects of Netting
​ ​
As Presented with
Effects of Netting
​
Non-current assets
​ ​ ​ $ 101,275 ​ ​ ​ ​ $ (87,339) ​ ​ ​ ​ $ 13,936 ​ ​
Current assets
​ ​ ​ ​ 92,611 ​ ​ ​ ​ ​ (64,872) ​ ​ ​ ​ ​ 27,739 ​ ​
Total assets
​ ​ ​ $ 193,886 ​ ​ ​ ​ $ (152,211) ​ ​ ​ ​ $ 41,675 ​ ​
Non-current liabilities
​ ​ ​ ​ (1,261,369) ​ ​ ​ ​ ​ 83,568 ​ ​ ​ ​ ​ (1,177,801) ​ ​
Current liabilities
​ ​ ​ ​ (362,483) ​ ​ ​ ​ ​ 68,643 ​ ​ ​ ​ ​ (293,840) ​ ​
Total liabilities
​ ​ ​ $ (1,623,852) ​ ​ ​ ​ $ 152,211 ​ ​ ​ ​ $ (1,471,641) ​ ​
Total net assets (liabilities)
​ ​ ​ $ (1,429,966) ​ ​ ​ ​ $ — ​ ​ ​ ​ $ (1,429,966) ​ ​
 
F-87
 
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, 2023
​ ​
June 30, 2022
​
Net gain (loss) on commodity derivatives settlements(a)
​ ​ ​ $ 54,525 ​ ​ ​ ​ $ (468,731) ​ ​
Net gain (loss) on interest rate swaps(a)
​ ​ ​ ​ (2,824) ​ ​ ​ ​ ​ 828 ​ ​
Gain (loss) on foreign currency hedges(a)
​ ​ ​ ​ (521) ​ ​ ​ ​ ​ — ​ ​
Total gain (loss) on settled derivative instruments
​ ​ ​ $ 51,180 ​ ​ ​ ​ $ (467,903) ​ ​
Gain (loss) on fair value adjustments of unsettled financial instruments(b)
​ ​ ​ ​ 760,933 ​ ​ ​ ​ ​ (1,205,938) ​ ​
Total gain (loss) on derivative financial instruments
​ ​ ​ $ 812,113 ​ ​ ​ ​ $ (1,673,841) ​ ​
​
(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 financings 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. 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.
2023 Modifications and Extinguishments
In February 2023, the Company sold puts in ABS III for approximately $9,045 and replaced them with swaps to maintain the appropriate level and composition of derivatives at both the legal entity and full-company level. The Company also monetized an additional $8,401 in net modifications, primarily comprised of swap terminations. As these modifications were made in the normal course of business for the six months ended June 30, 2023, they were recorded on the Company’s Consolidated Statement of Financial Position and are presented as an operating activity in the Consolidated Statement of Cash Flows.
2022 Modifications and Extinguishments
In February 2022, the Company adjusted portions of its commodity derivative portfolio across its legal entities to ensure that it maintained 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 adjustments by entering into new commodity derivative 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 for ABS III and ABS IV that collectively increased the value of the Company’s derivative position by an equal amount, and were required under the respective ABS III and ABS IV indentures. 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, and in October 2022 the Company completed the ABS V and ABS VI financing arrangements, respectively, and made similar commodity 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, driven primarily by the purchase of long-dated puts that increased the value of the Company’s derivative position by an equal amount, and were required under the ABS V indenture. Under the ABS VI
 
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financing, the Company paid $32,242 from the proceeds of the financing to increase the value of certain pre-existing derivative contracts that were novated to the ABS VI legal entity at closing. The Company recorded the payments as new derivative financial instruments on its Consolidated Statement of Financial Position.
Refer to Note 11 for additional information regarding ABS financing arrangements.
Other commodity derivative contract modifications made during the normal course of business for the year ended December 31, 2022 totaled $133,573 which the Company recorded on its Consolidated Statement of Financial Position. As these modifications were made in the normal course of business, the Company has presented these as an operating activity in the Consolidated Statement of Cash Flows. These modifications were primarily associated with elevating the Company’s weighted average hedge floor to take advantage of the high price environment experienced in 2022 over a longer term. The trades were primarily comprised of swap enhancements and the extinguishment of standalone call options.
Subsequent Event
Subsequent to June 30, 2023, the Company monetized an additional $9,240 in purchased puts associated with its ABS hedge books and transitioned the monetized positions into long-dated swap agreements.
NOTE 8 — SHARE CAPITAL
The Company has one class of common shares which carry the right to one vote at annual general meetings of the Company. As of June 30, 2023, the Company had no limit on the amount of authorized share capital and all shares in issue were fully paid.
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 February 2023, the Company placed 128,444 new shares at $1.27 per share (£1.05) to raise gross proceeds of $162,757 (approximately £134,866). Associated costs of the placing were $5,969. The Company used the proceeds to fund the Tanos II transaction, discussed in Note 4.
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 and the Employee Share Purchase Plan (the “ESPP”). 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, 2023, the EBT reissued 5,914 shares to settle vested share-based awards and ESPP purchases. No shares were purchased by the EBT during the six months ended June 30, 2023. No shares were reissued from the EBT during the six months ended June 30, 2022. 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). As of June 30, 2023, the EBT held 8,116 shares.
Repurchase of Shares
During the six months ended June 30, 2023, the Company repurchased 200 treasury shares at an average price per share of $1.05 totaling $213. No treasury shares were repurchased during the six months ended June 30, 2022.
 
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Settlement of Warrants
In July 2022, the Company entered into an agreement to cancel 132 warrants (the “Warrants”) held by certain former Mirabaud Securities Limited (“Mirabaud”) employees for an aggregate principal amount of approximately $56 (approximately £46). The former employees surrendered the Warrants to the Company for cancellation. Concurrently, the Company entered into an agreement to exercise 224 Warrants held by certain former Mirabaud employees for an aggregate principal amount of approximately $201 (approximately £166). The former employees surrendered the Warrants to the Company for cancellation in exchange for an equivalent number of shares of common stock. Following this purchase and exercise, no warrants remain outstanding.
In February 2022, the Company entered into an agreement to cancel 477 Warrants held by certain former Mirabaud Securities Limited (“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 £187). The former employees surrendered the Warrants to the Company for cancellation in exchange for an equivalent number of shares of common stock. Following this purchase and exercise, 355 warrants remained 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 January 1, 2023
​ ​ ​ ​ 828,935 ​ ​ ​ ​ $ 11,503 ​ ​ ​ ​ $ 1,052,959 ​ ​
Issuance of share capital (equity placement)
​ ​ ​ ​ 128,444 ​ ​ ​ ​ ​ 1,555 ​ ​ ​ ​ ​ 155,233 ​ ​
Issuance of EBT shares (equity compensation)
​ ​ ​ ​ 5,914 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares (share buyback program)
​ ​ ​ ​ (200) ​ ​ ​ ​ ​ (2) ​ ​ ​ ​ ​ — ​ ​
Balance as of June 30, 2023
​ ​ ​ ​ 963,093 ​ ​ ​ ​ $ 13,056 ​ ​ ​ ​ $ 1,208,192 ​ ​
​ ​ ​
Number of Shares
​ ​
Total Share
Capital
​ ​
Total Share
Premium
​
Balance as of January 1, 2022
​ ​ ​ ​ 849,655 ​ ​ ​ ​ $ 11,571 ​ ​ ​ ​ $ 1,052,959 ​ ​
Issuance of share capital (settlement of warrants)
​ ​ ​ ​ 513 ​ ​ ​ ​ ​ 5 ​ ​ ​ ​ ​ — ​ ​
Issuance of share capital (equity compensation)
​ ​ ​ ​ 792 ​ ​ ​ ​ ​ 7 ​ ​ ​ ​ ​ — ​ ​
Issuance of EBT shares (equity compensation)
​ ​ ​ ​ 1,760 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares (EBT)
​ ​ ​ ​ (15,790) ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​
Repurchase of shares (share buyback program)
​ ​ ​ ​ (7,995) ​ ​ ​ ​ $ (80) ​ ​ ​ ​ $ — ​ ​
Balance as of December 31, 2022
​ ​ ​ ​ 828,935 ​ ​ ​ ​ ​ 11,503 ​ ​ ​ ​ ​ 1,052,959 ​ ​
NOTE 9 — 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
​
Declared on November 14, 2022
​ ​
$0.0438
​ ​
£0.0361
​ ​
March 3, 2023
​ ​
March 28, 2023
​ ​
957,379
​ ​
$41,885
​
Declared on March 21, 2023
​ ​
$0.0438
​ ​
£0.0343
​ ​
May 26, 2023
​ ​
June 30, 2023
​ ​
963,293
​ ​
42,144
​
Paid during the six months ended June 30, 2023
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
$84,029
​
 
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​ ​ ​
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
​
Declared on March 22, 2022
​ ​
$0.0425
​ ​
£0.0343
​ ​
May 27, 2022
​ ​
June 30, 2022
​ ​
850,548
​ ​
36,148
​
Declared on May 16, 2022
​ ​
$0.0425
​ ​
£0.0366
​ ​
September 2, 2022
​ ​
September 26, 2022
​ ​
845,881
​ ​
35,950
​
Declared on August 8, 2022
​ ​
$0.0425
​ ​
£0.0345
​ ​
November 25, 2022
​ ​
December 28, 2022
​ ​
828,935
​ ​
 35,230 
​
Paid during the year ended December 31, 2022
​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
$143,455
​
On May 9, 2023 the Company proposed a dividend of $0.04375 per share. The dividend will be paid on September 29, 2023 to shareholders on the register on September 1, 2023. 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, 2023.
Dividends are waived on shares held in the EBT.
Subsequent Events
On September 1, 2023 the Directors recommended a dividend of $0.04375 per share. The dividend will be paid on December 29, 2023 to shareholders on the register on December 1, 2023. 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, 2023.
NOTE 10 — ASSET RETIREMENT OBLIGATIONS
The Company records a liability for the present value of the estimated future decommissioning costs on 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 by approximately 2095 consistent with the Company’s reserve calculations which were independently evaluated by the Company’s independent engineers for the year ended December 31, 2022. 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. No such contractual agreements or statutes were in place for the Company’s production facilities and pipelines for the six months ended June 30, 2023 and year ended December 31, 2022.
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 U.S. 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 U.S. Energy BB and BBB bond index which economically aligns with the underlying long-term and unsecured
 
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liability. Based on this evaluation the net discount rate used in the calculation of the decommissioning liability in 2023 and 2022 was 3.6% and 3.6%, respectively.
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, 2023
​ ​
December 31, 2022
​
Balance at beginning of period
​ ​ ​ $ 457,083 ​ ​ ​ ​ $ 525,589 ​ ​
Additions(a)
​ ​ ​ ​ 3,241 ​ ​ ​ ​ ​ 24,395 ​ ​
Accretion
​ ​ ​ ​ 13,991 ​ ​ ​ ​ ​ 27,569 ​ ​
Asset retirement costs
​ ​ ​ ​ (2,077) ​ ​ ​ ​ ​ (4,889) ​ ​
Disposals(b)
​ ​ ​ ​ (6,314) ​ ​ ​ ​ ​ (16,779) ​ ​
Revisions to estimate(c)
​ ​ ​ ​ (12,942) ​ ​ ​ ​ ​ (98,802) ​ ​
Balance at end of period
​ ​ ​ $ 452,982 ​ ​ ​ ​ $ 457,083 ​ ​
Less: Current asset retirement obligations
​ ​ ​ ​ 4,517 ​ ​ ​ ​ ​ 4,529 ​ ​
Non-current asset retirement obligations
​ ​ ​ $ 448,465 ​ ​ ​ ​ $ 452,554 ​ ​
​
(a)
Refer to Note 4 for additional information regarding acquisitions and divestitures.
​
(b)
Associated with the divestiture of natural gas and oil properties in the normal course of business.
​
(c)
As of June 30, 2023, the Company performed normal revisions to its asset retirement obligations, which resulted in a $12,942 decrease in the liability. This decrease was comprised of a $15,695 decrease attributable to a marginally higher discount rate which was offset by an increase of $2,753 in cost revisions for our recent experiences. The marginal changes in the discount rate are a result of a decline in bond yield volatility over the first half of the year. As of December 31, 2022, the Company performed normal revisions to its asset retirement obligations, which resulted in a $98,802 decrease in the liability. This decrease was comprised of a $144,656 decrease attributable to a higher discount rate. The higher discount rate was a result of macroeconomic factors spurred by the increase in bond yields which have elevated with U.S. treasuries to combat the current inflationary environment. Partially offsetting this decrease was $29,357 in cost revisions based on the Company’s recent asset retirement experiences and a $16,497 timing revision for the acceleration of the Company’s retirement plans made possible by the recent asset retirement acquisitions that improve the Company’s asset retirement capacity through the growth of its operational capabilities.
​
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 of June 30, 2023.
ARO Sensitivity
​ ​
+10%
​ ​
-10%
​
Discount rate
​ ​ ​ $ (45,986) ​ ​ ​ ​ $ 53,270 ​ ​
Timing
​ ​ ​ ​ 27,910 ​ ​ ​ ​ ​ (30,578) ​ ​
Cost
​ ​ ​ ​ 45,208 ​ ​ ​ ​ ​ (45,208) ​ ​
NOTE 11 — BORROWINGS
The Company’s borrowings consist of the following amounts as of the reporting date as follows:
​ ​ ​
June 30, 2023
​ ​
December 31, 2022
​
Credit Facility (Weighted average interest rate of 8.65% and 7.42%, respectively)(a)
​ ​ ​ $ 265,000 ​ ​ ​ ​ $ 56,000 ​ ​
ABS I Notes (Interest rate of 5.00%)
​ ​ ​ ​ 111,007 ​ ​ ​ ​ ​ 125,864 ​ ​
ABS II Notes (Interest rate of 5.25%)
​ ​ ​ ​ 136,550 ​ ​ ​ ​ ​ 147,458 ​ ​
ABS III Notes (Interest rate of 4.875%)
​ ​ ​ ​ 295,151 ​ ​ ​ ​ ​ 319,856 ​ ​
 
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​ ​ ​
June 30, 2023
​ ​
December 31, 2022
​
ABS IV Notes (Interest rate of 4.95%)
​ ​ ​ ​ 113,609 ​ ​ ​ ​ ​ 130,144 ​ ​
ABS V Notes (Interest rate of 5.78%)
​ ​ ​ ​ 329,381 ​ ​ ​ ​ ​ 378,796 ​ ​
ABS VI Notes (Interest rate of 7.50%)
​ ​ ​ ​ 183,758 ​ ​ ​ ​ ​ 212,446 ​ ​
Term Loan I (Interest rate of 6.50%)
​ ​ ​ ​ 112,433 ​ ​ ​ ​ ​ 120,518 ​ ​
Miscellaneous, primarily for real estate, vehicles and
equipment
​ ​ ​ ​ 8,319 ​ ​ ​ ​ ​ 7,084 ​ ​
Total borrowings
​ ​ ​ $ 1,555,208 ​ ​ ​ ​ $ 1,498,166 ​ ​
Less: Current portion of long-term debt
​ ​ ​ ​ (231,819) ​ ​ ​ ​ ​ (271,096) ​ ​
Less: Deferred financing costs
​ ​ ​ ​ (42,325) ​ ​ ​ ​ ​ (48,256) ​ ​
Less: Original issue discounts
​ ​ ​ ​ (8,274) ​ ​ ​ ​ ​ (9,581) ​ ​
Total non-current borrowings, net
​ ​ ​ $ 1,272,790 ​ ​ ​ ​ $ 1,169,233 ​ ​
​
​
(a)
Represents the variable interest rate as of period end.
​
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 2022, the Company amended and restated the credit agreement governing its Credit Facility. The amendment enhanced the alignment with the Company’s stated ESG initiatives by including sustainability performance targets (“SPTs”) similar to those included in the ABS III, IV, V and VI notes, extended the maturity of the Credit Facility to August 2026. In March 2023, the Company performed its semi-annual redetermination and the borrowing base was resized to $375,000 reflective of the Tanos II collateral and changes in commodity pricing.
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 quarterly basis. Available borrowings under the Credit Facility were $98,640 as of June 30, 2023 which considers the impact of $11,360 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. The restricted payment provision governs the Company’s ability to make discretionary payments such as dividends, share repurchases, or other discretionary payments. DP RBL Co LLC must comply with the following restricted payments test in order to make discretionary payments (i) leverage is less than 1.5x and borrowing base availability is >25% (ii) leverage is between 1.5x and 2.0x, free cash flow must be positive and borrowing base availability must be >15% (iii) leverage is between 2.0x and 2.5x, free cash flow must be positive and borrowing base availability must be >20% (iv) the Company’s restricted payments are restricted when leverage exceeds 2.5x for DP RBL Co LLC.
Additional covenants require DP RBL Co LLC 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, 2023.
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
 
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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 2020 Carbon and EQT acquisitions. The Term Loan I is secured by certain producing assets acquired in connection with the Carbon, Blackbeard and Tapstone acquisitions.
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, 2023 and 2022, the Company incurred $3,911 and $4,455 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, 2023.
ABS I Notes
In November 2019, the Company 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 $200,000 at par. 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. During the six months ended June 30, 2023 and 2022, the Company incurred $2,993 and $3,734 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% rate per annum. The fair value of the ABS I Notes approximates the carrying value as of June 30, 2023. In the event that ABS I has cash flow in excess of the required payments, ABS I is required to pay between 50% to 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 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 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, the Company 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 $200,000. The ABS II Notes 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 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, 2023 and 2022, the Company incurred $4,174 and $4,798 in interest related to the ABS II Notes, respectively. The fair value of the ABS II Notes approximates the carrying value as of June 30, 2023.
In the event that ABS II has cash flow in excess of the required payments, ABS II is required to pay between 50% to 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 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 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 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
 
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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, the Company 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 $365,000 at par. The ABS III Notes are secured by certain of the Company’s upstream producing, 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, 2023 and 2022, the Company incurred $7,509 and $7,099 in interest related to the ABS III Notes, respectively. The fair value of the ABS III Notes approximates the carrying value as of June 30, 2023.
In the event that ABS III has cash flow in excess of the required payments, ABS III is required to pay between 50% to 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 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%.
ABS IV Notes
In February 2022, the Company 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 $160,000 at par. The ABS IV Notes are secured by a portion of the upstream producing assets acquired in connection with the Blackbeard Acquisition.
The ABS IV Notes accrue interest at a stated 4.950% 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, 2023 and 2022, the Company incurred $3,033 and $2,730 in interest related to the ABS IV Notes, respectively. The fair value of the ABS IV Notes approximates the carrying value as of June 30, 2023.
In the event that ABS IV has cash flow in excess of the required payments, ABS IV is required to pay between 50% to 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) 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 of such Payment Date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS IV is less than 80%, then 100%, else 0%; and (c) if the LTV for ABS IV is greater than 65%, then 100%, else 0%.
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 $445,000 at par. 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 5.780% 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, 2023 and 2022, the Company incurred $10,273 and $2,286 in interest related to the ABS V Notes, respectively. The fair value of the ABS V Notes approximates the carrying value as of June 30, 2023.
 
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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 of such payment date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS V is less than 80%, then 100%, else 0%; and (c) if the LTV for ABS V is greater than 65%, then 100%, else 0%.
ABS VI Notes
In October 2022, the Company formed Diversified ABS VI LLC (“ABS VI”), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary, to issue, jointly with Oaktree, BBB+ rated asset-backed securities in an aggregate principal amount of $460,000 ($235,750 to the Company, before fees, representative of its 51.25% ownership interest in the collateral assets). The ABS VI Notes were issued at a 2.63% discount and are secured primarily by the upstream assets that were jointly acquired with Oaktree in the 2021 Tapstone acquisition. Similar to the accounting treatment for acquisitions performed in connection with Oaktree, DEC has recorded it’s proportionate share of the note in its Consolidated Statement of Financial Position.
The ABS VI Notes accrue interest at a stated 7.50% rate per annum and have a final maturity date of November 2039 with an amortizing maturity of October 2031. Interest and principal payments on the ABS VI Notes are payable on a monthly basis. During the six months ended June 30, 2023 and the year ended December 31, 2022, the Company incurred $8,257 and $3,300 in interest related to the ABS VI Notes, respectively. The fair value of the ABS VI Notes approximates the carrying value as of June 30, 2023.
Based on whether certain performance metrics are achieved, ABS VI 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 the applicable 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 VI is less than 80%, then 100%, else 0%; and (c) if the LTV for ABS VI is greater than 75%, then 100%, else 0%.
Debt Covenants
ABS I, II, III, IV, V and VI 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 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-VI 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.
 
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As of June 30, 2023 the Company was in compliance with all financial covenants for the ABS Notes, Term Loan I and the Credit Facility.
Sustainability-Linked Borrowings
Credit Facility
The Credit Facility contains three SPTs which, depending on the Company’s performance thereof, may result in adjustments to the applicable margin with respect to borrowings thereunder:
•
GHG Emissions Intensity: The Company’s consolidated Scope 1 emissions and Scope 2 emissions, each measured as MT CO2e per MMcfe;
​
•
Asset Retirement Performance: The number of wells the Company successfully retires during any fiscal year; and
​
•
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 Credit Facility for each of these categories are aspirational and represent higher thresholds than the Company has publicly set for itself. 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 the Company’s performance of the SPTs.
ABS III & IV
In connection with the issuance of the ABS III & IV notes, the Company 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 & IV notes, the interest payable with respect to the subsequent interest accrual period will increase by five basis points. This score is not dependent on the Company meeting or exceeding any sustainability performance metrics but rather an overall assessment of the Company’s corporate ESG profile. Further, this score is not dependent on the use of proceeds of the ABS III & IV notes and there were no such restrictions on the use of proceeds other than pursuant to the terms of the Company’s Credit Facility. The Company informs the ABS III & IV note holders in monthly note holder statements as to any change in interest rate payable on the ABS III & IV notes as a result of the change in this sustainability score.
ABS V & VI
In addition, a “second party opinion provider” certified the terms of the ABS V & VI 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.
The ABS V & VI notes contain two SPTs. The Company must achieve, and have certified by April 28, 2027 for ABS V and May 28, 2027 for ABS VI (1) a reduction in Scope 1 and Scope 2 GHG emissions intensity to 2.85 MT CO2e/MMcfe, and/or (2) a reduction in Scope 1 natural gas emissions intensity to 1.12 MT CO2e/​MMcfe. For each of these SPTs that the Company fails to meet, or have certified by an external verifier that it has met, by April 28, 2027 for ABS V and May 28, 2027 for ABS VI, the interest rate payable with
 
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respect to the ABS V & VI notes will be increased by 25 basis points. In each case, an independent third-party assurance provider will be required to certify the Company’s performance of the above SPTs by the applicable deadlines.
Compliance
As of June 30, 2023 the Company met or was in compliance with all sustainability-linked debt metrics..
Future Maturities
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, 2023
​ ​
December 31, 2022
​
Not later than one year
​ ​ ​ $ 231,819 ​ ​ ​ ​ $ 271,096 ​ ​
Later than one year and not later than five years
​ ​ ​ ​ 972,846 ​ ​ ​ ​ ​ 778,887 ​ ​
Later than five years
​ ​ ​ ​ 350,543 ​ ​ ​ ​ ​ 448,183 ​ ​
Total borrowings
​ ​ ​ $ 1,555,208 ​ ​ ​ ​ $ 1,498,166 ​ ​
Finance Costs
The following table represents the Company’s finance costs for each of the periods presented:
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30, 2023
​ ​
June 30, 2022
​
Interest expense, net of capitalized and income amounts(a)
​ ​ ​ $ 58,768 ​ ​ ​ ​ $ 33,322 ​ ​
Amortization of discount and deferred finance costs
​ ​ ​ ​ 8,968 ​ ​ ​ ​ ​ 5,797 ​ ​
Other
​ ​ ​ ​ — ​ ​ ​ ​ ​ 43 ​ ​
Total finance costs
​ ​ ​ $ 67,736 ​ ​ ​ ​ $ 39,162 ​ ​
​
(a)
Includes payments related to borrowings and leases.
​
Financing Activities
Reconciliation of borrowings arising from financing activities:
​ ​ ​
Six Months Ended
​
​ ​ ​
June 30, 2023
​ ​
June 30, 2022
​
Balance at beginning of period
​ ​ ​ $ 1,440,329 ​ ​ ​ ​ $ 1,010,355 ​ ​
Acquired as part of a business combination
​ ​ ​ ​ — ​ ​ ​ ​ ​ 2,437 ​ ​
Proceeds from borrowings
​ ​ ​ ​ 840,230 ​ ​ ​ ​ ​ 1,730,200 ​ ​
Repayments of borrowings
​ ​ ​ ​ (782,990) ​ ​ ​ ​ ​ (1,392,883) ​ ​
Costs incurred to secure financing
​ ​ ​ ​ (1,730) ​ ​ ​ ​ ​ (24,579) ​ ​
Amortization of discount and deferred financing costs
​ ​ ​ ​ 8,968 ​ ​ ​ ​ ​ 5,797 ​ ​
Cash paid for interest
​ ​ ​ ​ (59,415) ​ ​ ​ ​ ​ (32,605) ​ ​
Finance costs and other
​ ​ ​ ​ 59,217 ​ ​ ​ ​ ​ 32,604 ​ ​
Balance at end of period
​ ​ ​ $ 1,504,609 ​ ​ ​ ​ $ 1,331,326 ​ ​
Subsequent Events
From time to time the Company enters into financing arrangements which maximize the lending value of its collateral to bolster liquidity. In August 2023, the Company entered into a credit agreement providing it the ability to borrow up to $135,000 in loans and extensions of credit from the lender upon meeting conditions considered customary for agreements of this nature. The borrowing base is primarily a function of the value of the natural gas and oil properties that will collateralize the lending arrangement. The Credit
 
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Facility has an interest rate of SOFR plus an additional spread that ranges from 4.00% to 5.00% based on the period drawn. The legal maturity for the credit agreement is August 24, 2026.
NOTE 12 — OTHER LIABILITIES
(Amounts in thousands, except per share and per unit data)
The following table includes details of other liabilities as of the periods presented:
​ ​ ​
June 30, 2023
​ ​
December 31, 2022
​
Other non-current liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Other non-current liabilities(a)
​ ​ ​ $ 2,687 ​ ​ ​ ​ $ 5,375 ​ ​
Total other non-current liabilities
​ ​ ​ $ 2,687 ​ ​ ​ ​ $ 5,375 ​ ​
Other current liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Accrued expenses(b)
​ ​ ​ $ 97,299 ​ ​ ​ ​ $ 140,058 ​ ​
Taxes payable
​ ​ ​ ​ 41,336 ​ ​ ​ ​ ​ 41,907 ​ ​
Net revenue clearing(c)
​ ​ ​ ​ 60,746 ​ ​ ​ ​ ​ 186,244 ​ ​
Asset retirement obligations – current
​ ​ ​ ​ 4,517 ​ ​ ​ ​ ​ 4,529 ​ ​
Revenue to be distributed(d)
​ ​ ​ ​ 98,803 ​ ​ ​ ​ ​ 90,899 ​ ​
Total other current liabilities
​ ​ ​ $ 302,701 ​ ​ ​ ​ $ 463,637 ​ ​
​
(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 the Company for the administrative expansion necessary with acquired growth and is amortized to G&A expense over the life of the promote.
​
(b)
As of June 30, 2023 accrued expenses primarily consisted of hedge settlements payable, accrued capital projects and operating expenses. The year-over-year decrease is primarily a result of a decrease in hedge settlements payable of $46,071 due to lower commodity prices year-over-year.
​
(c)
Net revenue clearing is estimated revenue that is payable to third-party working interest owners. The year-over-year decrease is a result of lower commodity prices year-over-year.
​
(d)
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 year-over-year as a result of our acquisitions and recurring operating activity.
​
NOTE 13 — 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.
​
 
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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 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.
Leases
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 determined, the Company uses its incremental borrowing rate.
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, SOFR curve, and volatility factors.
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, 2023 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 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
 
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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.
There were no transfers between fair value levels for the six months ended June 30, 2023.
The following table includes the Company’s financial instruments as at the periods presented:
​ ​ ​
June 30, 2023
​ ​
December 31, 2022
​
Cash and cash equivalents
​ ​ ​ $ 4,208 ​ ​ ​ ​ $ 7,329 ​ ​
Trade receivables and accrued income
​ ​ ​ ​ 195,038 ​ ​ ​ ​ ​ 296,781 ​ ​
Other non-current assets
​ ​ ​ ​ 3,678 ​ ​ ​ ​ ​ 4,351 ​ ​
Other non-current liabilities(a)
​ ​ ​ ​ (936) ​ ​ ​ ​ ​ (1,669) ​ ​
Other current liabilities(b)
​ ​ ​ ​ (256,848) ​ ​ ​ ​ ​ (417,201) ​ ​
Derivative financial instruments at fair value
​ ​ ​ ​ (679,029) ​ ​ ​ ​ ​ (1,429,966) ​ ​
Leases
​ ​ ​ ​ (33,308) ​ ​ ​ ​ ​ (28,862) ​ ​
Borrowings
​ ​ ​ ​ (1,555,208) ​ ​ ​ ​ ​ (1,498,166) ​ ​
Total ​ ​ ​ $ (2,322,405) ​ ​ ​ ​ $ (3,067,403) ​ ​
​
(a)
Excludes the long-term portion of the value associated with the upfront promote received from Oaktree.
​
(b)
Includes accrued expenses, net revenue clearing and revenue to be distributed. Excludes taxes payable and asset retirement obligations.
​
NOTE 14 — CONTINGENCIES
Litigation And Regulatory Proceedings
The Company is involved in various pending legal issues 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, 2023, the Company did not have any material amounts accrued related to litigation or regulatory matters. For any matters where it is not possible to estimate the amount of any additional loss, or range of loss that is reasonably possible, no amounts have been accrued for, 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 material compliance as of June 30, 2023. 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 15 — RELATED PARTY TRANSACTIONS
The Company had no related party activity in 2023 or 2022.
 
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NOTE 16 — SUBSEQUENT EVENTS
The Company determined the need to disclose the following material transactions that occurred subsequent to June 30, 2023, which have been described within each relevant footnote as follows:
Description
​ ​
Footnote
​
Acquisitions and Divestitures ​ ​ Note 4 ​
Derivative Financial Instruments ​ ​ Note 7 ​
Dividends ​ ​ Note 9 ​
Borrowings ​ ​ Note 11 ​
 
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