DRS/A: Draft registration statement submitted by Emerging Growth Company under Securities Act Section 6(e) or by Foreign Private Issuer under Division of Corporation Finance policy
Published on September 12, 2023
As confidentially submitted to the Securities and Exchange Commission on September 12, 2023.
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Confidential Submission No. 7
to
to
FORM F-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
THE SECURITIES ACT OF 1933
Diversified Energy Company plc
(Exact Name of Registrant as Specified in its Charter)
(Exact Name of Registrant as Specified in its Charter)
Not Applicable
(Translation of Registrant’s name into English)
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England and Wales
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1311
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Not Applicable
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(State or Other Jurisdiction of
Incorporation or Organization) |
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(Primary Standard Industrial
Classification Code Number) |
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(I.R.S. Employer
Identification No.) |
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1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909
Birmingham, Alabama 35242
Tel: +1 205 408 0909
(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)
Benjamin Sullivan
Diversified Energy Company plc
1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909
Diversified Energy Company plc
1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
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David J. Miller
Ryan J. Lynch Latham & Watkins LLP 300 Colorado Street, Suite 2400 Austin, Texas 78701 +1 737 910 7300 |
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James Inness
Latham & Watkins (London) LLP 99 Bishopsgate London EC2M 3XF United Kingdom +44 20 7710 1000 |
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Douglas V. Getten
Preston Bernhisel Garrett H. Hughey Baker Botts L.L.P. 910 Louisiana Street, Suite 3200 Houston, Texas 77002 +1 713 229 1234 |
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Derek Jones
Baker Botts (UK) LLP Level 30, 20 Fenchurch Street London EC3M 3BY United Kingdom +44 20 7726 3636 |
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Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.
If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☐
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933. Emerging growth company ☒
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the U.S. Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
†
The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
TABLE OF CONTENTS
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For investors outside the United States: neither we nor the underwriters have done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction, other than the United States, where action for that purpose is required. Persons outside the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of our ordinary shares and the distribution of this prospectus outside the United States.
Neither we nor the underwriters have authorized anyone to provide you with any information or to make any representations other than those contained in this prospectus, any amendment or supplement to this prospectus, or in any free writing prospectus we have prepared, and neither we nor the underwriters take responsibility for, and can provide no assurance as to the reliability of, any other information others may give you. Neither we nor the underwriters are making an offer to sell, or seeking offers to buy, these securities in any jurisdiction where the offer or sale is not permitted. The information contained in this prospectus is accurate only as of the date on the cover page of this prospectus, regardless of the time of delivery of this prospectus or the sale of ordinary shares. Our business, financial condition, results of operations and prospects may have changed since the date on the cover page of this prospectus. We will update this prospectus as required by law, including with respect to any material change affecting us or our business prior to the completion of this offering.
i
COMMONLY USED DEFINED TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the natural gas and oil industry:
“Basin.” A large natural depression on the earth’s surface in which sediments accumulate.
“Bbl.” Barrel or barrels of oil or natural gas liquids.
“Boe.” Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
“Boepd.” Barrel of oil equivalent per day.
“Btu or British Thermal Unit.” A British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
“Development wells.” Wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“Drilling.” means any activity related to drilling pad make-ready costs, rig mobilization and creating a wellbore in order to facilitate the ultimate production of hydrocarbons.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses, taxes and the royalty burden.
“E&P.” Exploration and production of natural gas, NGLs and oil.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
“Gross acres or gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Henry Hub.” A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a high angle to vertical (which can be greater than 90 degrees) in order to stay with a specified interval.
“Hydraulic fracturing.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
“IFRS.” International Financial Reporting Standards, as issued by the International Accounting Standards Board.
“IASB.” The International Accounting Standards Board.
“LIBOR.” London Inter-bank Offered Rate, which is a market rate of interest.
“MBbls.” One thousand barrels of oil, condensate or NGL.
“Mboe.” One thousand Boe.
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“Mboepd.” One thousand Boe per day.
“Mcf.” One thousand cubic feet of natural gas.
“Mcfe.” One thousand cubic feet of natural gas equivalent.
“MMBoe.” One million Boe.
“MMBtu.” One million British Thermal Units.
“MMcf.” One million cubic feet of natural gas.
“MMcfe.” One million cubic feet of natural gas equivalent.
“MMcfepd.” One million cubic feet of natural gas equivalent per day.
“Mont Belvieu.” A mature trading hub with a high level of liquidity and transparency that sets spot and futures prices for NGLs.
“MtCO2e.” Metric tons of carbon dioxide equivalent.
“Net acres or net wells.” The sum of the fractional working interest owned in gross acres or gross wells, as the case may be. For example, an owner who has a 50% interest in 100 acres owns 50 net acres and an owner who has a 50% interest in 100 wells owns 50 net wells.
“NGL or NGLs.” Natural gas liquids, such as ethane, propane, butane and natural gasoline that are extracted from natural gas production streams.
“NYMEX.” The New York Mercantile Exchange.
“Oil.” Includes crude oil and condensate.
“OPEC.” The Organization of the Petroleum Exporting Countries.
“Possible reserves.” Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
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(vi)
Where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
“Probable Reserves.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Proved developed reserves.” Reserves of any category that can be expected to be recovered through:
(i)
existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)
installed extraction equipment and infrastructure operation at the time of the reserve estimate if the extraction is by means not involving a well.
“Proved reserves.” Those quantities of natural gas, NGLs and oil, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonable certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i)
The area of reservoir considered as proved includes:
(A)
the area identified by drilling and limited by fluid contacts, if any, and
(B)
adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas, NGLs or oil on the basis of available geosciences and engineering data.
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)
Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
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(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A)
successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)
the project has been approved for development by all necessary parties and entities, including governmental entities.
(v)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“Proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, NGLs or oil, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas, NGLs and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres, e.g., 40-acre spacing, and is established by regulatory agencies.
“SOFR.” The Secured Overnight Financing Rate, or SOFR.
“Standardized measure.” The year-end present value (discounted at an annual rate of 10%) of estimated future net cash flows to be generated from the production of proved reserves net of estimated income taxes associated with such net cash flows, as determined in accordance with FASB guidelines, without giving effect to non-property related expenses such as indirect general and administrative expenses and debt service or to depreciation, depletion and amortization. Standardized measure does not give effect to derivative transactions.
“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas, NGLs and oil regardless of whether such acreage contains proved reserves.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“U.S. GAAP.” Accounting principles generally accepted in the United States of America.
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“Wellbore” or “well.” The hole drilled by the bit that is equipped for natural gas, NGLs or oil production on a completed well. Also called a well or borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas, NGLs, oil or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
“Workover.” Operations on a producing well to restore or increase production.
“WTI.” West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.
Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and reserve data presented in this prospectus is as of December 31, 2022.
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ABOUT THIS PROSPECTUS
Except where the context otherwise requires or where otherwise indicated, the terms “Diversified Energy,” the “Company,” “DEC,” “we,” “us,” “our company” and “our business” refer to Diversified Energy Company plc, formerly Diversified Gas & Oil plc, together with its consolidated subsidiaries.
For the convenience of the reader, in this prospectus, unless otherwise indicated, translations from pound sterling into U.S. dollars were made at the rate of £1.00 to $ , which was the noon buying rate of the Federal Reserve Bank of New York on , 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.
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PRESENTATION OF FINANCIAL INFORMATION
This prospectus includes our audited consolidated financial statements as of and for the years ended December 31, 2022 and 2021, 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 International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”), which differ in certain significant respects from generally accepted accounting principles in the United States (“U.S. GAAP”). None of our financial statements were prepared in accordance with U.S. GAAP.
Our financial information is presented in U.S. dollars. Our fiscal year begins on January 1 and ends on December 31 of the same year. Certain amounts and percentages included in this prospectus have been rounded. Accordingly, in certain instances, the sum of the numbers in a column of a table may not exactly equal the total figure for that column.
All references in this prospectus to “$” mean U.S. dollars and all references to “£” and “GBP” mean pound sterling. We have made rounding adjustments to some of the figures included in this prospectus. Accordingly, numerical figures shown as totals in some tables may not be an arithmetic aggregation of the figures that preceded them.
Use of Non-IFRS Measures
Certain key operating metrics that are not defined under IFRS (alternative performance measures) are included in this prospectus. These non-IFRS measures are used by us to monitor the underlying business performance of the Company from period to period and to facilitate comparison with our peers. Since not all companies calculate these or other non-IFRS metrics in the same way, the manner in which we have chosen to calculate the non-IFRS metrics presented herein may not be compatible with similarly defined terms used by other companies. The non-IFRS metrics should not be considered in isolation of, or viewed as substitutes for, the financial information prepared in accordance with IFRS. Certain of the key operating metrics set forth below are based on information derived from our regularly maintained records and accounting and operating systems. See the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures” in this prospectus for reconciliations of such measures to the most directly comparable IFRS measures and reasons for the use of such non-IFRS measures.
Average Quarterly Dividend per Ordinary Share. Average Quarterly Dividend per Ordinary Share is reflective of the average of the dividends per ordinary share declared throughout the applicable fiscal year which gives consideration to changes in dividend rates and changes in the amount of shares outstanding. We use Average Quarterly Dividend per Ordinary Share as we seek to pay a consistent and reliable dividend to shareholders.
Adjusted EBITDA. As used herein, EBITDA represents earnings before interest, taxes, depletion, depreciation and amortization. Adjusted EBITDA includes adjusting for items that are not comparable period over period, namely, accretion of asset retirement obligation, other (income) expense, loss on joint and working interest owners receivable, gain on bargain purchase, (gain) loss on fair value adjustments of unsettled financial instruments, (gain) loss on natural gas and oil property and equipment, costs associated with acquisitions, other adjusting costs, non-cash equity compensation, (gain) loss on foreign currency hedge, net (gain) loss on interest rate swaps and items of a similar nature.
Adjusted EBITDA should not be considered in isolation or as a substitute for operating profit or loss, net income or loss, or cash flows provided by operating, investing and financing activities. However, we believe such measure is useful to an investor in evaluating DEC’s financial performance because it (1) is widely used by investors in the natural gas and oil industry as an indicator of underlying business performance; (2) helps investors to more meaningfully evaluate and compare the results of DEC’s operations from period to period by removing the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement; (3) is used in the calculation of a key metric in our revolving credit facility by and among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto (the “Credit Facility”) financial covenants; and (4) is used by the Company as a performance measure in determining executive compensation. When evaluating this measure, we believe investors also commonly find it useful to evaluate
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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 and Net-Debt-to-Adjusted EBITDA. As used herein, Net Debt represents total debt as recognized on the balance sheet less cash and restricted cash. Total debt includes DEC’s borrowings under the Credit Facility and borrowings under or issuances of, as applicable, its subsidiaries’ securitization facilities. Net Debt is a useful indicator of DEC’s leverage and capital structure.
As used herein, Net-Debt-to-Adjusted EBITDA, or “Leverage” or “Leverage Ratio,” is measured as Net Debt divided by Adjusted EBITDA. We believe that this metric is a key measure of DEC’s financial liquidity and flexibility and is used in the calculation of a key metric in one of the Credit Facility’s financial covenants. Our statutory auditor, PricewaterhouseCoopers LLP (“PwC”), has not audited, reviewed, examined, compiled, verified or performed any procedures with respect to the pro forma financial information.
Total Revenue, inclusive of 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 incudes the direct operating cost and the portion of general and administrative cost it takes to produce each Boe. This metric includes operating expense, employees, administrative costs and professional services and recurring allowance for credit losses, which include fixed and variable cost components. We believe that Adjusted EBITDA Margin is a useful measure of DEC’s profitability and efficiency as well as its earnings quality given its ability to measure the company on a more comparable basis period over period given we are often involved in transactions that are not comparable between periods.
Free Cash Flow. As used herein, Free Cash Flow represents net cash provided by operating activities less expenditures on natural gas and oil properties and equipment and cash paid for interest. We believe that Free Cash Flow is a useful indicator of DEC’s ability to generate cash that is available for activities other than capital expenditures. Management believes that Free Cash Flow provides investors with an important perspective on the cash available to service debt obligations, make strategic acquisitions and investments and pay dividends.
Adjusted Operating Cost per Boe. Adjusted Operating Cost per Boe is a metric that allows us to measure the direct operating cost and the portion of general and administrative cost it takes to produce each Boe. This metric, similar to Adjusted EBITDA Margin, includes operating expense, employees, administrative costs and professional services and recurring allowance for credit losses, which include fixed and variable cost components.
Employees, administrative costs and professional services. As used herein, employees, administrative costs and professional services represents total administrative expenses excluding cost associated with acquisitions, other adjusting costs and non-cash expenses. We use Employees, administrative costs and professional services because this measure excludes items that affect the comparability of results or that are not indicative of trends in the ongoing business.
PV-10. PV-10 is a non-IFRS measure because it excludes the effects of applicable income tax. Management believes that the presentation of the non-IFRS financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating natural gas and oil companies. PV-10 is not a measure of financial or operating performance under IFRS. PV-10 should not be considered as an alternative to the standardized measure as defined under IFRS. We have included a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, its most directly comparable IFRS measure, elsewhere in this prospectus. PV-10 differs from the standardized measure of discounted future net cash flows because it does not include the effects of income taxes. Neither PV-10 nor the standardized measure represents an estimate of fair market value of our natural gas and oil properties.
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MARKET AND INDUSTRY DATA
We obtained the industry, market and competitive position data in this prospectus from our own internal estimates, surveys and research, as well as from publicly available information, industry and general publications and research, surveys and studies.
Industry publications, research, surveys, studies and forecasts generally state that the information they contain has been obtained from sources believed to be reliable but that the accuracy and completeness of such information is not guaranteed. Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties as the other forward-looking statements in this prospectus. These forecasts and forward-looking information are subject to uncertainty and risk due to a variety of factors, including those described in the section titled “Risk Factors” found elsewhere in this prospectus. These and other factors could cause results to differ materially from those expressed in the forecasts or estimates from independent third parties and us.
TRADEMARKS AND TRADE NAMES
We have proprietary rights to trademarks used in this prospectus that are important to our business, many of which are registered under applicable intellectual property laws. Solely for convenience, trademarks and trade names referred to in this prospectus may appear without the “®” or “™” symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent possible under applicable law, our rights or the rights of the applicable licensor to these trademarks and trade names. We do not intend our use or display of other companies’ trademarks, trade names or service marks to imply a relationship with, or endorsement or sponsorship of us by, any other companies. Each trademark, trade name or service mark of any other company appearing in this prospectus is the property of its respective holder.
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PROSPECTUS SUMMARY
This summary highlights information contained elsewhere in this prospectus. This summary does not contain all the information that you should consider before deciding to invest in our ordinary shares. You should read the entire prospectus carefully, including the sections titled “Risk Factors,” “Business,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes to those consolidated financial statements before making an investment decision. We have provided definitions for certain natural gas and oil terms used in this prospectus in the section titled “Commonly Used Defined Terms” beginning on page ii of this prospectus. Unless the context requires otherwise, references in this prospectus to “Diversified,” “DEC,” “the Company,” “we,” “us,” “our” or “ours” refer to Diversified Energy Company plc and its subsidiaries.
The information presented in this prospectus assumes, unless otherwise indicated, that the underwriters do not exercise their option to purchase additional ordinary shares.
Company Overview
Diversified Energy Company plc
The Company, formerly Diversified Gas & Oil plc, is an independent energy company engaged in the production, marketing and transportation of natural gas as well as oil from its complementary onshore upstream and midstream assets, primarily located within the Appalachian and Central Regions of the United States. Our Appalachia assets consist primarily of producing wells in conventional reservoirs and the Marcellus and Utica shales, within Pennsylvania, Ohio, Virginia, West Virginia, Kentucky, and Tennessee, while our Central Region, located in Oklahoma, Louisiana, and portions of Texas, includes producing wells in multiple producing formations, including the Bossier, Haynesville Shale and Barnett Shale Plays, as well as the Cotton Valley and the Mid-Continent producing areas. We were incorporated in 2014 in the United Kingdom, and our predecessor business was co-founded in 2001 by our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., with an initial focus on primarily natural gas and also oil production in West Virginia. In recent years, we have grown rapidly by capitalizing on opportunities to acquire and enhance producing assets and leveraging the operating efficiencies that result from economies of scale. Since 2017, 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.
Our strategy is to acquire and manage natural gas and oil properties and our associated midstream assets to generate cash flows and maximize shareholder returns. For the six months ended June 30, 2023 and for the year ended December 31, 2022, we distributed approximately $84 million and $143 million, respectively, to our shareholders in the form of dividends. We actively seek to acquire high-quality producing conventional and unconventional natural gas and oil assets from industry participants seeking to divest assets either due to a desire to reallocate capital to other assets or raise cash proceeds. We target long-life producing assets at what we view as attractive valuations, and in our commercial evaluation, we typically attribute value to only the proved developed producing (“PDP”) portion of proved reserves and attribute minimal, if any, value to the proved undeveloped (“PUD”) portion of proved reserves, and no value to probable or possible reserves. Our target assets are characterized by multi-decade production profiles and low decline rates, and we place a particular focus on assets whose value we believe can be enhanced by complementary midstream infrastructure or by our operational and marketing framework.
We seek to improve the performance and operations of our acquired assets, which often have not received significant attention or necessary investment from their former owners. This improvement is achieved through our deployment of rigorous field management programs and/or refreshing infrastructure on wells that may have been poorly maintained. Through operational efficiencies, we demonstrate our ability to maximize value by enhancing production while lowering costs and improving well productivity. These production enhancement techniques also enable us to reduce the methane emissions profile of our wells. We further enhance the value of our assets by leveraging our midstream gathering pipeline infrastructure, which allows us to further diversify and expand our third-party revenue, optimize pricing, increase flow assurance and eliminate third-party costs and inefficiencies.
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Our experienced management team has a track record of consistently delivering per share growth in profitability and cash flow. As a result of our competitive strengths, we believe that we are well positioned to continue to grow for our shareholders.
Our senior management team is comprised of experienced individuals with decades of combined experience in the natural gas and oil sector, including in the Appalachian Basin where our operations historically have been concentrated. In particular, we benefit from the experience of our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., who is highly experienced in sourcing accretive acquisitions and securing the related financing. The management team is complemented by a talented operational leadership team with significant operational experience in U.S. onshore natural gas and oil basins. We have also sought to bolster this experience with the operating expertise of long-standing field staff of any acquired operations. These experienced field-level employees have a relentless focus on execution and an in-depth understanding of, and extensive experience working with, our assets, which is enhanced under our management’s leadership and operating strategy.
Commitment to Operational Excellence and Our Environmental, Social and Governance Initiatives
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 striving to act as a careful steward of our assets will improve revenue and margins through captured methane emissions while reducing operating costs, which benefits our profitability. This focus on operational excellence, including the aim of reducing of methane emissions, also benefits the environment and communities in which we operate. We also work to extend the lives of existing mature wells, generally not engaging in development activity and, through our state-monitored, safe and systematic asset retirement program, permanently retire end of life wells and eliminate any potential associated emissions by safely plugging and abandoning the retired wells. We believe that by deploying our proprietary asset retirement infrastructure rather than needing to engage contractors in such activities, we are able to more nimbly react to operating conditions as they develop, changes in asset performance and to relative changes in the emissions profiles of our producing wells, thereby reducing potential methane emissions while also increasing margins and cost efficiency.
Our operations team developed our proprietary Smarter Asset Management (“SAM”) program, which is focused on enhancing our operational results by slowing production declines and returning shut-in wells to production. The SAM program underpins our focus on efficient production and flow from our wells and midstream assets through consistent operating efforts and an environmentally-conscious focus, which results in improved production, thereby partially offsetting natural production declines, lowering operating costs and emissions and improving asset integrity, all with the goal of generating higher cash flow. Additionally, through the daily implementation of our SAM program, which includes wellhead compression management, fluid load reduction and pump-jack optimization, among other techniques, we have intentionally and continuously taken actions directed at trying to reduce unintended natural gas emissions, while carefully managing our general and administrative expenses.
We aim to serve both domestic and global daily energy needs with reliable, efficient, abundant, clean and affordable natural gas. In our view, natural gas is and will be a critical resource in the energy mix into the foreseeable future and will continue to play a vital role in our global and domestic energy supply. We have consistently tried to drive our operations towards sustainability and efficiency, and we believe we are at the forefront of U.S. natural gas and oil producers in our commitment to environmental, social and governance (“ESG”) programs and initiatives. We remain keenly aware of the balance between climate, energy security and sustainability. We believe that natural gas can and must play a key role in the global economic transition to a lower-carbon economy, so we are committed to developing our role as a responsible steward of the natural resources we manage, working to lower our operational carbon footprint. Further, we believe that our natural gas production and systems play an important role in ensuring a stable energy supply as we are positioned to help meet the demand for clean, reliable energy safely and efficiently for decades to come. 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 a high standard of 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
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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 acquisitions 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.
Throughout 2022 and through June 30, 2023, we remained diligently focused on our previously stated near-term goals to reduce Scope 1 methane intensity by 30% by 2026 and by 50% by 2030 (assuming a 2020 baseline). Our dedicated human capital and financial investments aimed largely at leak detection and repair efforts in our Appalachian upstream assets and conversion of natural gas-driven pneumatic devices to compressed air across our portfolio contributed to a 20% reduction in reported methane emissions intensity for year-end 2022.
While our current environmental focus is on methane reductions, we also continue work on our marginal abatement cost curve (“MACC”) to help shape 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 the Iconic Air 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.
In addition to our guiding values for ESG management, we also utilize the United Nations’ Sustainable Development Goals (“SDG”), which calls on individuals, corporations and governments to work together towards the ultimate, unified goal of creating a better and more sustainable future for all citizens globally. We challenge ourselves to consider these topics and more when we effectuate our business model, corporate strategy, ESG commitments, daily operations and risk management practices. We believe our OneDEC approach supports important contributions to the SDGs to which our business model aligns yet also provides added opportunities for us to make continuous improvement and contribution.
A principal component of our OneDEC culture is also our greatest asset, our employees. We strive to foster a corporate culture ripe with opportunities for professional collaboration and development, personal growth and enjoyment, and where all employees feel valued and supported in the work they do. As part of a coordinated diversity and engagement strategy within our recruitment processes, we have engaged a number of external agencies across specific geographic areas of focus within our operating footprint in support of driving diversity within the Company. During 2022, the percentage of minorities that comprised our employee base increased to 3.6% from 2.7%. The percentage of women in our employee base at December 31, 2022 was 10%, with the majority serving in production support roles. We seek to generate a diverse candidate pool from which we can identify and hire the most qualified individuals, regardless of
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background, to the benefit of the Company and our stakeholders. Our board of directors consists of three females and five males, and our senior management, including our executive committee and its direct reports, but excluding the two executive directors, consisted of 90 employees, including 32 females (36%) and 58 males (64%). Our board of directors continues to demonstrate diversity in a wider sense, with directors from the U.S. as well as the UK, bringing a range of domestic and international experience to our board of directors. Our board of directors will continue to review and evaluate the Company’s board of directors and committee composition and intends to continue further progress with independence and diversity.
Finally, we invest in our people and the communities in which we operate. 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. As part of our commitment to the communities in which we operate, we also successfully launched a new grant-giving program to support organizations or projects across our 10-state footprint that have a positive, direct and long-lasting impact on the communities in which our employees live and work. Our grant process seeks to support programs which address one or more of three societal focus areas, including (1) community enrichment, (2) education and workforce development and (3) the environment. We consider it a privilege to support organizations and programs with these societal focus areas with both our financial support and our volunteer efforts.
Assets and Operations
We have historically operated within the Appalachian Basin, which covers an area of 185,500 square miles. While the area came to prominence following the discovery of significant shale gas reserves in 2009 in the Utica and Marcellus shales, it has been a major producer of natural gas, natural gas liquids (“NGLs”) and oil from conventional vertical well development since the late 19th century, making it the oldest producing basin within the United States.
Our asset base is comprised of approximately 77,598 conventional and unconventional, mature, long- life, low decline natural gas and oil producing wells on a gross productive basis. These mature wells benefit from simple and low-cost maintenance operations and require low ongoing capital expenditures. Our well portfolio exhibits an average long-term decline rate of approximately 8.5% and contains certain wells that have an expected life of greater than 50 years. In addition to the upstream assets, our portfolio contains approximately 17,700 miles of natural gas gathering pipelines and a network of compression stations and processing facilities.
The map below shows the geographic locations of our assets as of December 31, 2022.
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We have an established reputation in the marketplace as a consolidator of assets in the Appalachian Basin, and we believe we are one of the few operators in the United States with sufficient access to capital to make acquisitions at scale. Through a series of acquisitions beginning in 2021, we have quickly built scale in the Central Region, located in Oklahoma, Louisiana and portions of Texas, including the Cotton Valley, Bossier, Haynesville Shale, Barnett Shale Plays, as well as the Mid-Continent producing areas. Our goal is to replicate the success we have had in the Appalachian region to our new operations in the Central Region, which we believe presents considerable growth opportunities.
We focus on producing natural gas, NGLs and oil from established conventional and mature unconventional wells. Based on our operational experience with our assets, we believe that many of the wells in our inventory have low-risk, up-hole potential that has yet to be fully quantified. Additionally, most of
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our acreage is held by production, and due to the significant well control and geologic understanding of our portfolio, we believe there is also potential for significant, low-cost, low-risk developmental drilling opportunity within our assets.
The production profiles of the wells across these formations demonstrate similar characteristics. Most of these formations produce natural gas and/or oil on a hyperbolic curve with an initial rapid decline followed by gradual decline of production over a long period of time. This modest, later-life rate of decline enables us to predict and plan with a high level of confidence the future production profile of our producing assets.
Summary Reserve Data
Summary of Reserves as of December 31, 2022
The following table provides our reserves, PV-10 and the Standardized Measure. Our reserves, Standardized Measure and PV-10 are calculated using SEC rules regarding reserve reporting currently in effect, including the use of an average price, calculated as prices equal to the 12-month unweighted arithmetic average of the first day of the month prices for each of the preceding 12 months as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (“SEC Pricing”).
Estimated Proved Reserves(1)
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SEC Pricing as of 12/31/2022(1)
Total |
| |||
Natural gas (MMcf)
|
| | | | 4,349,611 | | |
Natural gas liquids (MBbl)
|
| | | | 101,931 | | |
Oil (MBbl)
|
| | | | 14,830 | | |
Total (MBoe)(2)
|
| | | | 841,696 | | |
PV-10(3) | | | | $ | 8,825,462 | | |
Standardized measure of discounted future net cash flows
|
| | | $ | 6,743,100 | | |
Estimated Proved Developed Reserves | | | | | | | |
Natural gas (MMcf)
|
| | | | 4,340,779 | | |
Natural gas liquids (MBbl)
|
| | | | 101,931 | | |
Oil (MBbl)
|
| | | | 14,830 | | |
Total (MBoe)(2)
|
| | | | 840,224 | | |
Estimated Proved Undeveloped Reserves | | | | | | | |
Natural gas (MMcf)
|
| | | | 8,832 | | |
Natural gas liquids (MBbl)
|
| | | | — | | |
Oil (MBbl)
|
| | | | — | | |
Total (MBoe)(2)
|
| | | | 1,472 | | |
(1)
Our historical SEC reserves, PV-10 and Standardized Measure were calculated using SEC Pricing. For natural gas volumes, the average Henry Hub spot price was adjusted for gravity, quality, local conditions, gathering and transportation fees, and distance from market. For oil and NGL volumes, the average WTI price 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)
Assumes a ratio of six Mcf of natural gas per Bbl.
(3)
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 the “standardized measure of future net cash flows,” the most directly comparable GAAP measure, because it does not include the effects of income taxes on future net cash flows. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. Investors should be cautioned that neither PV-10 nor the standardized measure represents an
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estimate of the fair market value of our proved reserves. See the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures.”
Strategies
Optimization of long-life, low-decline assets to enhance margins and improve cash flow
Unlike many companies in the upstream sector, we are not primarily focused on capital-intensive drilling and development. Our stewardship model focuses on acquiring existing, long-life, low-decline producing wells and, occasionally, their associated midstream assets, and then efficiently managing the assets through our SAM program to improve or restore production, reduce unit-operating costs and generate consistent cash flow before safely and permanently retiring those assets at the end of their useful lives.
When we acquire new assets, we often seek to retain many of the experienced employees who have historically serviced those assets while integrating our SAM program into their day-to-day operations. While we are not primarily a midstream company, we strategically seek to maximize the value of our producing assets through complementary midstream systems that can be fully integrated into our upstream portfolio. These assets are typically located in areas where we are a large producer, allowing market access to higher prices and the opportunity to reroute production when adjoining, third-party systems are constrained or result in lower pricing for product sales. We also earn additional revenue for transporting third-party operators’ production through our system, effectively providing a subsidy to the operating costs of our midstream system and ultimately improving consolidated operating margins.
We intend to continue optimizing our operations in a manner that prioritizes the generation of cash flow. Our principal focus is on operating assets, not drilling new production wells, thereby allowing us to optimize PDP revenues and cost streams. For the six months ended June 30, 2023, we reported net income of $631 million. Excluding the mark-to-market loss on long- dated derivative valuations as well as other customary non-cash or non-recurring adjustments, we reported Adjusted EBITDA of $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% driven primarily by our growth through acquisitions. For the year ended December 31, 2022, we reported a net loss of $621 million. Excluding the mark-to-market loss on long-dated derivative valuations as well as other customary non-cash or non-recurring adjustments, we reported Adjusted EBITDA of $503 million compared to $343 million for the year ended December 31, 2021, representing an increase of 47% driven by our growth through acquisitions and the elevation of our hedged floor which increased from $2.97 per Mcf as of December 31, 2021 to $3.63 per Mcf as of December 31, 2022.
Generate consistent shareholder returns through vertical integration, strategic hedging and cost optimization
We intend to continue our strategy of delivering value to shareholders through a combination of paying dividends to our shareholders, reinvesting in accretive growth, repaying debt and investing in ESG initiatives. From time-to-time, we will also evaluate and engage share repurchase opportunities and engage in such returns of value to our shareholders. Since our initial public offering of ordinary shares on the London Stock Exchange in 2017 (the “LSE IPO”) and as of June 30, 2023, we have paid an aggregate of $575 million in dividends and have repurchased approximately $103 million of our outstanding shares. Since our LSE IPO, we have steadily increased our dividend to our most recent annual rate of $0.17 per share during the year ended December 31, 2022, representing an eightfold increase. The long-term dividend sustainability, as well as the ability to incur debt purposefully structured to provide for amortization and thus decrease leverage over time, is supported by a conservative hedging strategy to insulate cash flows from commodity price volatility and provide visibility over cash flows. As a result of this strategy, we have been successful in securing Adjusted EBITDA margins of approximately 50%. See the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures.”
We aim to maximize shareholder value by realizing operational efficiencies and the thorough implementation of vertical integration. To achieve this strategy, we utilize our SAM program to partially offset natural production declines and also leverage our scale and cost efficiencies to reduce unit operating costs and improve margins, particularly in respect of newly acquired assets. We proactively seek to manage our operating costs and believe that there is further room to optimize the operating cost base of the business given our scale and approach to vertical integration, particularly for recently acquired assets. Our midstream assets also help to support cost reduction by providing operational control over the transportation of our
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production, thereby allowing us to optimize pricing through a selection of delivery points and providing increased operational control. Our asset retirement infrastructure provides cost efficiency in our plugging and abandonment activities.
Disciplined growth through accretive acquisitions of producing assets
We intend to maintain our disciplined approach to acquisitions and, while we pursue opportunistic growth, we will also focus on assets that we believe will provide long-term accretive cash flow generation. We intend to continue pursuing this strategy as we believe we are well positioned to benefit from ongoing trends in the U.S. exploration and production industry where incumbent operators seek exit strategies to divest non-core assets to create the necessary capital to drill and develop their core leasehold positions.
We have a track record as an established consolidator, and we believe we are one of the few operators able to continue to make acquisitions at scale. While we have historically focused on the Appalachian Basin, the fragmented operator landscape across the U.S. has created significant opportunity to find accretive asset packages that meet the goals of our historical investment standards, primarily due to our ability to effectively apply SAM program techniques to new assets as well as leveraging favorable regional commodity pricing, ample takeaway capacity and opportunities to build accretive scale around the position.
We have most recently demonstrated this strategic infill growth ability in our Central Region which spans across Louisiana, Oklahoma and Texas. Through four acquisitions in 2021 we quickly entered the region and began building scale. During 2022 we continued this growth by imitating our success in Appalachia and expanding our footprint with practical bolt-on upstream, midstream, and processing facility acquisitions, providing systematic synergistic growth in the region. Our investment in Central Region acquisitions in 2022 totaled $307 million and bolstered our 2022 average daily production by 7%.
We continue to look for other opportunities that fit our investment criteria across the U.S. and will continue to expand our footprint in accordance with our stated strategy. We will not unduly burden our balance sheet with additional debt for non-accretive growth, and as a result, we intend to maintain disciplined target leverage ratios.
As a further measure to bolster the scale at which we acquire assets, in October 2020, we entered into a definitive participation agreement (the “Strategic Participation Agreement”) with funds managed by Oaktree Capital Management, L.P. (“Oaktree”) to jointly identify and fund future PDP acquisition opportunities that we identify from time-to-time (the “Oaktree Funding Commitment”). The Oaktree Funding Commitment provides for up to an aggregate of $1.0 billion over three years for mutually agreed upon PDP acquisitions, including approximately $573 million remaining under the initial commitment as of June 30, 2023.
Maintain a strong balance sheet with ability to opportunistically access capital markets
We actively manage our balance sheet and seek to maintain a leverage ratio at or below 2.5 to 1.0 after giving effect to acquisitions and any related financing arrangements. At December 31, 2022, we had a Standardized Measure coverage ratio (defined as Standardized Measure divided by total debt) of 4.5 to 1.0, a PV-10 coverage ratio (defined as PV-10 divided by total debt) of 5.9 to 1.0 and $191 million in liquidity. See the subsection titled “—Non-IFRS Financial Measures” for a reconciliation of PV-10 to Standardized Measure. As added context as of December 31, 2022, 96% of our outstanding indebtedness had an amortizing structure allowing for scheduled monthly repayments. These low interest fixed-rate structures contain hedge protection for the collateralized assets ensuring strong margins that secure the structured borrowing repayments. Structures of this nature allow us to naturally deleverage over time in a resilient and disciplined manner that compliments the natural low decline nature of our asset base. We also maintain sufficient liquidity such that we can be well positioned in the market to capitalize on acquisition opportunities as they become available. We intend to ensure that future acquisitions are made at attractive valuations and conservatively capitalized in order to maintain a modest leverage ratio.
Operate assets in a safe, efficient manner with what we believe are industry-leading ESG initiatives
We believe that natural gas is and will be a critical resource in the energy mix into the foreseeable future and will continue to play a vital role in our global and domestic energy supply. In addition to consistently
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implementing our SAM program across our asset base, we strive to be at the leading edge of our industry with respect to the implementation of emissions-detection technology as well as emissions reduction targets.
Additionally, we continue to strive for high standards of governance. The board of directors of the Company, of which three of the eight directors are female and a majority are independent, has a diverse set of experiences and knowledge base which provides for constructive dialogue between both directors and management with respect to ESG and other matters. Our board of directors oversees the development of our climate change strategy which aims to position the Company at the heart of the energy transition, based on responsible stewardship of existing assets, and is highly experienced and continuously educated in this strategic area. The Sustainability and Safety Committee evaluates all issues relating to climate change on behalf of the board of directors, including changes in regulation and policy and other external, macro- level developments relating to climate change. The Audit and Risk Committee oversees the Enterprise Risk Management (“ERM”) process, including assessing and managing climate risk, while the Remuneration Committee is responsible for developing a compensation structure for senior management linked, in part, to ESG- and climate-related metrics. Overseeing the size and composition of the board of directors, the Nomination and Governance Committee is responsible for ensuring the board of director’s collective skill set is positioned to adequately understand and strategically lead climate-related decisions and opportunities for the Company. Climate-related matters are also discussed regularly as part of our board of directors’ meetings. We also seek to be proactive in social stewardship and have engaged global consultants and financial advisors to ensure high quality disclosures and regulatory compliance as well as ESG ratings agencies to ensure reported data and company actions are accurate and validated.
Strengths
Low-risk and low-cost portfolio of assets
We benefit from a highly diversified portfolio of low-risk and low-cost assets. These assets include conventional and unconventional natural gas and oil producing wells located across the geologically and politically low-risk states of Tennessee, Kentucky, Virginia, West Virginia, Ohio, Pennsylvania, Texas, Oklahoma and Louisiana. As a result, our performance is not materially impacted by the performance of any individual well or well pad. In addition to these upstream assets, our portfolio contains approximately 17,700 miles of natural gas gathering pipelines and a network of compression and processing facilities that are complementary to our upstream assets and enhance margins by reducing third-party tariffs and optimize pricing through route selection. We also have agreements with third parties to gather and transport their produced natural gas, which effectively provides a subsidy to the operating costs of our midstream system and ultimately improves consolidated operating margins. We do not rely on exploration or development activity to increase reserves or drive production. As a result, we are not as exposed to the capital-intensive development and drilling risks that come with a more traditional development model. Our wells are mature and benefit from simple and low-cost maintenance operations, as illustrated by our low relative gathering and transportation (“G&T”) cost per Boe, requiring low ongoing capital expenditures for a highly cash generative asset base and which positions us to effectively manage the nature, timing and amount of capital expenditure invested in our assets. Our gathering and transportation cost for the six months ended June 30, 2023 was $3.28 per Boe as compared with the average of what we view as our U.S. peers of $5.94 per Boe. This provides us with control and flexibility over future investment programs, which is a key competitive advantage in light of the historic volatility in natural gas and oil prices. For the six months ended June 30, 2023, excluding acquisitions, our total capital expenditures were 5.1% of total net income, or 11.4% of total Adjusted EBITDA. See the subsection titled “—Non-IFRS Financial Measures” for a reconciliation of Adjusted EBITDA to net income (loss).
Long-life and low-decline production
We benefit from stable, long-life and low-decline production which provides a durable, highly visible source of cash flow. This cash generation profile allows us to maintain a prudent allocation of cash flows consisting of dividend payments, debt reduction and organic growth reinvestment, as well as investments in ESG initiatives. The vast majority of our wells are past their high decline phase and into their period of exponential decline, a later period in a well’s life, where decline rates are lower and generally demonstrate a more stable production profile. Our decline rate of approximately 8.5%, when taking into account our acquisitions completed in 2022, is lower than many public, development-focused gas-weighted exploration
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and production companies where decline rates in excess of 30% are not uncommon. Our portfolio performance is underpinned by our SAM program, which enhances production from producing wells and returns other non-producing wells to a productive state.
High margin assets benefiting from significant scale and owned midstream and asset retirement infrastructure
We benefit from consistent production with low decline rates from our high-quality assets and significant scale that, when paired with our relatively low average cost of production, gives rise to high profit margins and consistent cash flows. Corporate scale, enhanced by our acquisitions, allows us to leverage the extensive expertise of our work force and the experience accumulated by our employees from operating in gas-focused regions for many years, driving innovation and best practices. Our significant operational scale is enhanced by our vertically integrated operations, in particular our midstream infrastructure, which results in increased control of our production flow, increased operational efficiencies, and increased third-party revenue streams, as well as our asset retirement infrastructure and operations, which allow us to reduce costs in respect of plugging and abandonment obligations.
Highly experienced management and operational team
Our senior management team is comprised of experienced individuals with a combined over 100 years of experience in the natural gas and oil sector. In particular, we benefit from the knowledge of our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., who is highly experienced in sourcing accretive acquisitions and securing the related financing. The management team is complemented by a senior operational team with an exceptional understanding of U.S. onshore gas basins, spanning an average of over 30 years of operational experience. These experienced employees have a relentless focus on execution and an in-depth understanding of, and extensive experience working with, our assets. This operational experience culminates in our SAM program. Our management team remains focused on efficient and effective management of production and operations while carefully controlling general and administrative expenses.
Track record of successful consolidation and integration of acquired assets
Following the development of the U.S. onshore natural gas and oil industry through what is commonly referred to as the ‘shale revolution’, there has been a significant supply of conventional and unconventional assets that have become available as a result of a number of U.S. exploration and development companies selling producing acreage viewed as non-core to their operations, as well as distressed sellers looking to supplement low cash flow with asset sale proceeds. Simultaneously, this increase in supply of assets has been met by limited demand due to market uncertainty and relatively weak capital markets. We are well positioned to exploit these continued consolidation opportunities. Our management team has demonstrated our ability to source, fund and execute acquisitions that significantly enhance shareholder value. We have completed 24 acquisitions since 2017 with a combined purchase consideration of approximately $2.6 billion, while seeking to maintain a disciplined leverage position of 2.5 to 1.0 or less after giving effect to acquisitions and any related financing arrangements.
A proactive and innovative approach to asset retirement
We embrace our responsibilities to the United States, our local communities and our environment. With safety and environmental stewardship as top priorities, we designed our asset retirement program to permanently retire wells that have reached the end of their economic lives. Unlike the higher risk, complex and costly “decommissioning” of deep, offshore wells with large production platforms, the retirement of our predominantly shallow, onshore wells and their small land footprints is far less complex and costly.
In 2017, after the LSE IPO, we proactively began to meet regularly with state officials to develop a long-term plan to retire our growing portfolio of long-life wells. Collaborating with the appropriate regulators, we designed our retirement activities to be equitable for all stakeholders with an emphasis on the environment. This collaborative plan is one that we are now greatly outpacing as evidenced by the 214 wells that we retired during 2022. This achievement accomplished our publicly stated goal of retiring 200 wells by 2023 a year early and more than doubles the 80 wells we agreed to retire under our state arrangements. We hold 10-year asset retirement plans with the states of Kentucky and Ohio and 15-year plans with the
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states of Pennsylvania and West Virginia. This was made possible by the focus and investments we made in asset retirement during 2022.
During 2022, we made investments that allowed us to meaningfully expand our plugging capabilities through a series of acquisitions and as of December 31, 2022 we have 12 teams operating 15 rigs in Appalachia, representing a significant portion of the asset retirement capacity in the region. This growth has been a welcomed addition by state leaders and as a result we have been engaged by the states of West Virginia, Ohio, Pennsylvania and Kentucky to use our excess capacity to help retire their inventory of abandoned and orphan wells. We expect these relationships to continue to grow as we further solidify our position as a market leader in asset retirement.
Our asset retirement program reflects our solid commitment to a healthy environment, the surrounding community and its citizens and state regulatory authorities. We partner our highly skilled personnel with the necessary financial resources to responsibly manage our assets throughout their productive lives and retirement. We strive to meet or exceed our asset retirement obligations under state agreements and have a growing track record demonstrating our ability to succeed.
Acquisitions and Consolidation
We continue to identify attractive acquisition and investment opportunities to purchase additional producing assets in or around our existing footprint, as well as outside of the states in which we currently operate. Each target acquisition is evaluated within strict criteria and our disciplined approach to evaluating opportunities ensures that we only pursue those acquisitions that possess a consistent asset profile, compelling upside, and have the potential to drive positive cash flow per share. In addition, we also consider the emissions profiles of target acquisitions in our evaluations. The higher commodity price environment creates market opportunities to build on our strategy of value-accretive acquisitions as other companies seek exit strategies to divest non-core assets creating the necessary capital to drill and develop their core leasehold positions. We continue to explore opportunities and anticipate being active in a strong M&A market consistent with our proven strategy and successful track record of integrating and optimizing newly acquired assets.
Our Capital Expenditure Program and Liquidity
Our strategy to acquire and operate producing assets that generate cash flow margins of approximately 50% allows us to invest capital back into our operations. In addition, we plan to achieve “net zero” Scope 1 and Scope 2 emissions by 2040 through new investments aimed at emissions reductions, such as investments in methane emissions detection devices and conducting aerial scans of our assets.
The majority of our capital expenditures are focused on our midstream operations, which includes pipelines and compression, while the remaining capital expenditures are focused on emissions reductions initiatives, plugging capacity expansion, fleet, technology, upstream operations, and when prudent, may include development activities targeted at replacing production. Given our operational focus to acquire and operate mature conventional wells and unconventional wells with a shallow decline rate, we do not incur the same level of large capital expenditures associated with drilling and completion activities that would typically be incurred by other development focused exploration and production companies.
In 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 have maintained our distribution levels and paid $84 million in dividends ($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.
11
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.
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.
Summary of Risk Factors
Investing in our ordinary shares involves risks. You should carefully consider the risks described in the section titled “Risk Factors” immediately following this prospectus summary before making a decision to invest in our ordinary shares. These risks include, but are not limited to, the following:
•
Volatility and future decreases in natural gas, NGLs and oil prices could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
•
We face production risks and hazards that may affect our ability to produce natural gas, NGLs and oil at expected levels, quality and costs that may result in additional liabilities to us.
•
The levels of our natural gas and oil reserves and resources, their quality and production volumes may be lower than estimated or expected.
•
The present value of future net cash flows from our reserves, or PV-10, will not necessarily be the same as the current market value of our estimated natural gas, NGL and oil reserves.
•
We may face unanticipated increased or incremental costs in connection with decommissioning obligations such as plugging.
•
We may not be able to keep pace with technological developments in our industry or be able to implement them effectively.
•
The 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 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.
12
•
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 following this offering may adversely affect the liquidity and value of our ordinary shares.
•
Failure to comply with requirements to design, implement and maintain effective internal control over financial reporting could have a material adverse effect on our business.
•
If you purchase ordinary shares in this offering, you will suffer immediate dilution of your investment.
•
We are subject to certain tax risks, including changes in tax legislation in the United Kingdom and the United States.
Corporate 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 Alternative Investment Market (“AIM”) under the ticker “DGOC.” In May 2020, our shares were admitted to the premium segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE. The shares trading on AIM were cancelled concurrent to their admittance on the LSE. With the change in corporate name in 2021, our shares listed on the LSE began trading under the new ticker “DEC.”
Our principal executive offices are located at 1600 Corporate Drive, Birmingham, Alabama 35242, and our telephone number at that location is +1 205 408 0909. Our website address is www.div.energy. The information contained on, or that can be accessed from, our website does not form part of this prospectus. We have included our website address solely as an inactive textual reference.
Implications of Being an Emerging Growth Company and a Foreign Private Issuer
We qualify as an “emerging growth company” as defined in the U.S. Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As an emerging growth company, we may take advantage of specified reduced reporting and other requirements that are otherwise applicable generally to public companies in the United States. These provisions include:
•
an exemption from compliance with any requirement that the Public Company Accounting Oversight Board may adopt regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements;
13
•
reduced disclosure about our executive compensation arrangements;
•
an exemption from the non-binding advisory votes on executive compensation, including golden parachute arrangements; and
•
an exemption from the auditor attestation requirement in the assessment of our internal control over financial reporting pursuant to the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”).
As a result, we do not know if some investors will find our ordinary shares less attractive. The result may be a less active trading market for our ordinary shares, and the price of our ordinary shares may become more volatile. We may choose to take advantage of some or all these provisions until the last day of the fiscal year ending after the fifth anniversary of the offering or such earlier time that we are no longer an emerging growth company. We would cease to be an emerging growth company if we have more than $1.07 billion in total annual gross revenue, have more than $700 million in market value of our ordinary shares held by non-affiliates or issue more than $1.0 billion of non-convertible debt over a three-year period.
Our status as a foreign private issuer also exempts us from compliance with certain laws and regulations of the SEC and certain regulations of the . Consequently, we are not subject to all of the disclosure requirements applicable to U.S. public companies. For example, we are exempt from certain rules under the U.S. Securities and Exchange Act of 1934, as amended (“Exchange Act”) that regulate disclosure obligations and procedural requirements related to the solicitation of proxies, consents or authorizations applicable to a security registered under the Exchange Act. In addition, our executive officers and directors are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and related rules with respect to their purchases and sales of our securities. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. public companies. Accordingly, there may be less publicly available information concerning our company than there is for U.S. public companies.
In addition, foreign private issuers are not required to file their annual report on Form 20-F until 120 days after the end of each fiscal year, while U.S. domestic issuers that are accelerated filers are required to file their annual report on Form 10-K within 75 days after the end of each fiscal year. Foreign private issuers are also exempt from Regulation FD (Fair Disclosure) of the Exchange Act, aimed at preventing issuers from making selective disclosures of material information.
We may take advantage of these exemptions until such time as we no longer qualify as a foreign private issuer. In order to maintain our current status as a foreign private issuer, either a majority of our outstanding voting securities must be directly or indirectly held of record by non-residents of the United States, or, if a majority of our outstanding voting securities are directly or indirectly held of record by residents of the United States, a majority of our executive officers or directors may not be United States citizens or residents, more than 50% of our assets cannot be located in the United States and our business must be administered principally outside the United States.
We have taken advantage of certain of these reduced reporting and other requirements in this prospectus. Accordingly, the information contained herein may be different from the information you receive from other public companies in the United States which you hold equity securities.
14
THE OFFERING
Ordinary shares offered by us
ordinary shares.
Option to purchase additional ordinary shares
We have granted the underwriters an option to purchase up to an additional ordinary shares from us within 30 days of the date of this prospectus.
Ordinary shares to be outstanding immediately after this offering
ordinary shares (or ordinary shares if the underwriters exercise their option to purchase additional ordinary shares from us in full).
Use of proceeds
We estimate that the net proceeds to us from this offering will be approximately $ million, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, based on an assumed initial public offering price of $ per ordinary share, the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE on , 2023 (based on an assumed exchange rate of £1.00 to $ ).
The principal purposes of this offering are to create a public market for our ordinary shares in the United States, facilitate access to the public equity markets and increase our visibility in the marketplace. We intend to use the net proceeds from this offering for working capital, to fund incremental growth and other general corporate purposes, including possible acquisitions that we view as accretive to our business. See the section titled “Use of Proceeds.”
Risk factors
See the section titled “Risk Factors” and other information included in this prospectus for a discussion of factors you should carefully consider before deciding to invest in our ordinary shares.
Proposed Listing
We intend to apply to list our ordinary shares on the New York Stock Exchange under the symbol “DEC.”
LSE trading symbol
Our ordinary shares are listed on the LSE under the symbol “DEC.”
The number of our ordinary shares to be outstanding immediately after this offering is based on ordinary shares outstanding as of June 30, 2023, and excludes:
•
ordinary shares issuable upon the exercise of options outstanding under our 2017 Equity Incentive Plan (as defined herein) as of June 30, 2023 at a weighted-average exercise price of $ per share; and
•
ordinary shares reserved for future issuance under our 2017 Equity Incentive Plan as of June 30, 2023, as further described in the subsection titled “Management—Equity Compensation Arrangements—2017 Equity Incentive Plan.”
Unless otherwise indicated, all information in this prospectus assumes or gives effect to:
•
an initial public offering price of $ per ordinary share, the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2023 (based on an assumed exchange rate of £1.00 to $1. );
•
no exercise of the outstanding options described above after June 30, 2023; and
•
no exercise by the underwriters of their option to purchase up to additional ordinary shares in this offering.
15
SUMMARY CONSOLIDATED FINANCIAL AND OTHER DATA
We prepare our consolidated financial statements in accordance with IFRS as issued by the IASB. The following summary historical consolidated financial data as of December 31, 2022 and 2021, and for the six months ended June 30, 2023 and 2022 and for the years ended December 31, 2022 and 2021 has been derived from and our audited consolidated financial statements our unaudited interim condensed consolidated financial statements, which are included elsewhere in this prospectus. Our historical results for any prior period are not necessarily indicative of results expected in any future period and our quarterly results are not necessarily indicative of results expected for the full year ending 2023 nor any future periods.
The financial data set forth below should be read in conjunction with, and is qualified by reference to, the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our unaudited interim condensed consolidated financial statements and our audited consolidated financial statements and notes thereto included elsewhere in this prospectus.
Consolidated Statement of Comprehensive Income
| | |
Six Months Ended
|
| |
Year Ended
|
| ||||||||||||||||||
(In thousands, except per share and per unit data)
|
| |
June 30,
2023 |
| |
June 30,
2022 |
| |
December 31,
2022 |
| |
December 31,
2021 |
| ||||||||||||
Revenue
|
| | | $ | 487,305 | | | | | $ | 933,528 | | | | | $ | 1,919,349 | | | | | $ | 1,007,561 | | |
Operating expense
|
| | | | (227,299) | | | | | | (206,357) | | | | | | (445,893) | | | | | | (291,213) | | |
Depreciation, depletion and amortization
|
| | | | (115,036) | | | | | | (118,480) | | | | | | (222,257) | | | | | | (167,644) | | |
Gross profit
|
| | | | 144,970 | | | | | | 608,691 | | | | | | 1,251,199 | | | | | | 548,704 | | |
General and administrative expense
|
| | | | (55,156) | | | | | | (114,282) | | | | | | (170,735) | | | | | | (102,326) | | |
Allowance for expected credit losses
|
| | | | — | | | | | | — | | | | | | — | | | | | | 4,265 | | |
Gain (loss) on natural gas and oil property and equipment
|
| | | | 7,729 | | | | | | 1,050 | | | | | | 2,379 | | | | | | (901) | | |
Gain (loss) on derivative financial instruments
|
| | | | 812,113 | | | | | | (1,673,841) | | | | | | (1,758,693) | | | | | | (974,878) | | |
Gain on bargain purchases
|
| | | | — | | | | | | 1,249 | | | | | | 4,447 | | | | | | 58,072 | | |
Operating profit (loss)
|
| | | | 909,656 | | | | | | (1,177,133) | | | | | | (671,403) | | | | | | (467,064) | | |
Finance costs
|
| | | | (67,736) | | | | | | (39,162) | | | | | | (100,799) | | | | | | (50,628) | | |
Accretion of asset retirement obligation
|
| | | | (13,991) | | | | | | (14,003) | | | | | | (27,569) | | | | | | (24,396) | | |
Other income (expense)
|
| | | | 327 | | | | | | 171 | | | | | | 269 | | | | | | (8,812) | | |
Income (loss) before taxation
|
| | | | 828,256 | | | | | | (1,230,127) | | | | | | (799,502) | | | | | | (550,900) | | |
Income tax benefit (expense)
|
| | | | (197,324) | | | | | | 294,877 | | | | | | 178,904 | | | | | | 225,694 | | |
Net income (loss)
|
| | | | 630,932 | | | | | | (935,250) | | | | | | (620,598) | | | | | | (325,206) | | |
Other comprehensive income (loss)
|
| | | | (88) | | | | | | 132 | | | | | | 940 | | | | | | 51 | | |
Total comprehensive income (loss)
|
| | | $ | 630,844 | | | | | $ | (935,118) | | | | | $ | (619,658) | | | | | $ | (325,155) | | |
Earnings (loss) per share–basic
|
| | | $ | 0.68 | | | | | $ | (1.10) | | | | | $ | (0.74) | | | | | $ | (0.41) | | |
Earnings (loss) per share–diluted
|
| | | $ | 0.67 | | | | | $ | (1.10) | | | | | $ | (0.74) | | | | | $ | (0.41) | | |
Weighted average shares outstanding–basic
|
| | | | 926,066 | | | | | | 849,621 | | | | | | 844,080 | | | | | | 793,542 | | |
Weighted average shares outstanding–diluted
|
| | | | 937,838 | | | | | | 849,621 | | | | | | 844,080 | | | | | | 793,542 | | |
16
Consolidated Statement of Financial Position
| | |
As of
|
| |||||||||||||||
(In thousands)
|
| |
June 30,
2023 |
| |
December 31,
2022 |
| |
December 31,
2021 |
| |||||||||
Assets | | | | | | | | | | | | | | | | | | | |
Total non-current assets
|
| | | $ | 3,424,296 | | | | | $ | 3,476,706 | | | | | $ | 3,157,070 | | |
Cash and cash equivalents
|
| | | | 4,208 | | | | | | 7,329 | | | | | | 12,558 | | |
Total current assets(1)
|
| | | | 334,501 | | | | | | 346,893 | | | | | | 324,581 | | |
Total assets
|
| | |
$
|
3,763,005
|
| | | |
$
|
3,830,928
|
| | | |
$
|
3,494,209
|
| |
Equity and Liabilities | | | | | | | | | | | | | | | | | | | |
Total equity
|
| | | $ | 560,998 | | | | | $ | (137,724) | | | | | $ | 663,950 | | |
Total non-current liabilities
|
| | | | 2,488,926 | | | | | | 2,837,022 | | | | | | 2,056,659 | | |
Total current liabilities
|
| | | | 713,081 | | | | | | 1,131,630 | | | | | | 773,600 | | |
Total liabilities
|
| | | $ | 3,202,007 | | | | | $ | 3,968,652 | | | | | $ | 2,830,259 | | |
Total equity and liabilities
|
| | |
$
|
3,763,005
|
| | | |
$
|
3,830,928
|
| | | |
$
|
3,494,209
|
| |
(1)
Excludes cash and cash equivalents.
Consolidated Statement of Cash Flows
| | |
Six Months Ended
|
| |
Year Ended
|
| ||||||||||||||||||
(In thousands)
|
| |
June 30,
2023 |
| |
June 30,
2022 |
| |
December 31,
2022 |
| |
December 31,
2021 |
| ||||||||||||
Statement of Cash Flows Data: | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital expenditures(1)
|
| | | $ | (32,332) | | | | | $ | (44,539) | | | | | $ | (86,079) | | | | | $ | (50,175) | | |
Net cash provided by (used in): | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating activities
|
| | | $ | 172,566 | | | | | $ | 204,987 | | | | | $ | 387,764 | | | | | $ | 320,182 | | |
Investing activities
|
| | | | (250,017) | | | | | | (122,118) | | | | | | (386,457) | | | | | | (627,712) | | |
Financing activities
|
| | | | 74,330 | | | | | | 91,915 | | | | | | (6,536) | | | | | | 318,709 | | |
(1)
Included within investing activities.
Other Financial Data and Key Ratios
Financial Metrics Summary
Certain key operating metrics that are not defined under IFRS (alternative performance measures) are presented below. 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.
17
Non-IFRS Financial Measures
Average Quarterly Dividend per Ordinary Share
| | |
Six Months Ended
|
| |
Year Ended
|
| ||||||||||||||||||
| | |
June 30,
2023 |
| |
June 30,
2022 |
| |
December 31,
2022 |
| |
December 31,
2021 |
| ||||||||||||
Declared on first quarter results 2023, 2022, 2022 and 2021
|
| | | $ | 0.04375 | | | | | $ | 0.04250 | | | | | $ | 0.04250 | | | | | $ | 0.04000 | | |
Declared on second quarter results 2023, 2022, 2022 and 2021
|
| | | | 0.04375 | | | | | | 0.04250 | | | | | | 0.04250 | | | | | | 0.04000 | | |
Declared on third quarter results 2022, 2021, 2022 and 2021
|
| | | | 0.04375 | | | | | | 0.04250 | | | | | | 0.04375 | | | | | | 0.04250 | | |
Declared on fourth quarter results 2022, 2021, 2022 and 2021
|
| | | | 0.04375 | | | | | | 0.04250 | | | | | | 0.04375 | | | | | | 0.04250 | | |
Trailing Twelve Months Average Quarterly Dividend per Ordinary Share
|
| | | $ | 0.04375 | | | | | $ | 0.04250 | | | | | $ | 0.04313 | | | | | $ | 0.04125 | | |
Trailing Twelve Months Total Dividends per Ordinary Share
|
| | | $ | 0.17500 | | | | | $ | 0.17000 | | | | | $ | 0.17250 | | | | | $ | 0.16500 | | |
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 |
| ||||||||||||
Net income (loss)
|
| | | $ | 630,932 | | | | | $ | (935,250) | | | | | $ | (620,598) | | | | | $ | (325,206) | | |
Finance costs
|
| | | | 67,736 | | | | | | 39,162 | | | | | | 100,799 | | | | | | 50,628 | | |
Accretion of asset retirement obligations
|
| | | | 13,991 | | | | | | 14,003 | | | | | | 27,569 | | | | | | 24,396 | | |
Other (income) expense
|
| | | | (327) | | | | | | (171) | | | | | | (269) | | | | | | 8,812 | | |
Income tax (benefit) expense
|
| | | | 197,324 | | | | | | (294,877) | | | | | | (178,904) | | | | | | (225,694) | | |
Depreciation, depletion and amortization
|
| | | | 115,036 | | | | | | 118,480 | | | | | | 222,257 | | | | | | 167,644 | | |
(Gain) loss on bargain purchases
|
| | | | — | | | | | | (1,249) | | | | | | (4,447) | | | | | | (58,072) | | |
(Gain) loss on fair value adjustments of unsettled financial instruments
|
| | | | (760,933) | | | | | | 1,205,938 | | | | | | 861,457 | | | | | | 652,465 | | |
(Gain) loss on natural gas and oil property and equipment(1)
|
| | | | (899) | | | | | | 515 | | | | | | 93 | | | | | | 901 | | |
Costs associated with acquisitions
|
| | | | 8,866 | | | | | | 6,935 | | | | | | 15,545 | | | | | | 27,743 | | |
Other adjusting costs(2)
|
| | | | 3,376 | | | | | | 67,033 | | | | | | 69,967 | | | | | | 10,371 | | |
Non-cash equity compensation
|
| | | | 4,417 | | | | | | 4,069 | | | | | | 8,051 | | | | | | 7,400 | | |
(Gain) loss on foreign currency hedge
|
| | | | 521 | | | | | | — | | | | | | — | | | | | | 1,227 | | |
(Gain) loss on interest rate swap
|
| | | | 2,824 | | | | | | (828) | | | | | | 1,434 | | | | | | 530 | | |
Total adjustments
|
| | | $ | (348,068) | | | | | $ | 1,159,010 | | | | | $ | 1,123,552 | | | | | $ | 668,351 | | |
Adjusted EBITDA
|
| | | $ | 282,864 | | | | | $ | 223,760 | | | | | $ | 502,954 | | | | | $ | 343,145 | | |
(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 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.
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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 |
| ||||||||||||
Total revenue
|
| | | $ | 487,305 | | | | | $ | 933,528 | | | | | $ | 1,919,349 | | | | | $ | 1,007,561 | | |
Net gain (loss) on commodity derivative instruments(1)
|
| | | | 54,525 | | | | | | (468,731) | | | | | | (895,802) | | | | | | (320,656) | | |
Total Revenue, Inclusive of Settled Hedges
|
| | | $ | 541,830 | | | | | $ | 464,797 | | | | | $ | 1,023,547 | | | | | $ | 686,905 | | |
Adjusted EBITDA
|
| | | $ | 282,864 | | | | | $ | 223,760 | | | | | $ | 502,954 | | | | | $ | 343,145 | | |
Adjusted EBITDA Margin(2)
|
| | | | 52% | | | | | | 48% | | | | | | 49% | | | | | | 50% | | |
(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 |
| ||||||||||||
Net cash provided by operating activities
|
| | | $ | 172,566 | | | | | $ | 204,987 | | | | | $ | 387,764 | | | | | $ | 320,182 | | |
LESS: Expenditures on natural gas and oil properties and equipment
|
| | | | (32,332) | | | | | | (44,539) | | | | | | (86,079) | | | | | | (50,175) | | |
LESS: Cash paid for interest
|
| | | | (59,415) | | | | | | (32,605) | | | | | | (82,936) | | | | | | (41,623) | | |
Free Cash Flow
|
| | | $ | 80,819 | | | | | $ | 127,843 | | | | | $ | 218,749 | | | | | $ | 228,384 | | |
Adjusted Operating Cost per Boe
| | |
Six Months Ended
|
| |
Year Ended
|
| ||||||||||||||||||
(In thousands)
|
| |
June 30,
2023 |
| |
June 30,
2022 |
| |
December 31,
2022 |
| |
December 31,
2021 |
| ||||||||||||
Total production (MBoe)
|
| | | | 25,697 | | | | | | 24,620 | | | | | | 49,354 | | | | | | 43,257 | | |
Total operating expense
|
| | | $ | 227,299 | | | | | $ | 206,357 | | | | | $ | 445,893 | | | | | $ | 291,213 | | |
Employees, administrative costs and professional services
|
| | | | 38,497 | | | | | | 36,245 | | | | | | 77,172 | | | | | | 56,812 | | |
Recurring allowance for credit losses
|
| | | | — | | | | | | — | | | | | | — | | | | | | (4,265) | | |
Adjusted Operating Cost
|
| | | $ | 265,796 | | | | | $ | 242,602 | | | | | $ | 523,065 | | | | | $ | 343,760 | | |
Adjusted Operating Cost per Boe
|
| | | $ | 10.34 | | | | | $ | 9.85 | | | | | $ | 10.60 | | | | | $ | 7.95 | | |
PV-10
| | |
As of
|
| |||||||||
(In thousands)
|
| |
December 31,
2022 |
| |
December 31,
2021 |
| ||||||
| | |
SEC Pricing(1)
|
| |||||||||
PV-10 | | | | | | | | | | | | | |
Pre-tax (Non-GAAP)(2)
|
| | | $ | 8,825,462 | | | | | $ | 4,037,016 | | |
PV of Taxes
|
| | | | (2,082,362) | | | | | | (703,925) | | |
Standardized Measure
|
| | | $ | 6,743,100 | | | | | $ | 3,333,091 | | |
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(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 and $3.60 per MMBtu as of December 31, 2022 and 2021, 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 and $66.55 per Bbl as of December 31, 2022 and 2021, 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 and 2021 was prepared without giving effect to taxes or hedges. PV-10 is a non-GAAP and non-IFRS financial measure and generally differs from Standardized Measure, the most directly comparable GAAP measure, because it does not include the effects of income taxes on future net cash flows. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the Standardized Measure because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. While the Standardized Measure is free cash dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. Investors should be cautioned that neither PV-10 nor the Standardized Measure represents an estimate of the fair market value of our proved reserves.
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RISK FACTORS
An investment in our ordinary shares involves a high degree of risk. You should carefully consider the risks and uncertainty described below, together with all of the other information in this prospectus, including the sections titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Special Note Regarding Forward-Looking Statements” and our consolidated financial statements and the related notes thereto, before deciding to invest in our ordinary shares. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations. Our business, financial condition or results of operations could be materially and adversely affected by any of the following risks or additional risks and uncertainties that are currently immaterial or unknown. The trading price and value of our ordinary shares could decline due to any of these risks, and you may lose all or part of your investment.
Risks Relating to Our Business, Operations and Industry
Volatility and future decreases in natural gas, NGLs and oil prices could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
Our business, results of operations, financial condition, cash flows or prospects depend substantially upon prevailing natural gas, NGL and oil prices, which may be adversely impacted by unfavorable global, regional and national macroeconomic conditions, including but not limited to instability related to the military conflict in Ukraine and the COVID-19 pandemic. Natural gas, NGLs and oil are commodities for which prices are determined based on global and regional demand, supply and other factors, all of which are beyond our control.
Historically, prices for natural gas, NGLs and oil have fluctuated widely for many reasons, including:
•
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.
21
It is impossible to accurately predict future gas, NGL and oil price movements. Historically, natural gas prices have been highly volatile and subject to large fluctuations in response to relatively minor changes in the demand for natural gas. The recent spike in U.S. Henry Hub natural gas prices to $9.68 per MMBtu at the end of August 2022 as compared to a historically low price in June 2020 of $1.48 per MMBtu highlights the volatile nature of commodity prices.
The economics of producing from some wells and assets may also result in a reduction in the volumes of our reserves which can be produced commercially, resulting in decreases to our reported reserves. Additionally, further reductions in commodity prices may result in a reduction in the volumes of our reserves. We might also elect not to continue production from certain wells at lower prices, or our license partners may not want to continue production regardless of our position.
Each of these factors could result in a material decrease in the value of our reserves, which could lead to a reduction in our natural gas, NGLs and oil development activities and acquisition of additional reserves. In addition, certain development projects or potential future acquisitions could become unprofitable as a result of a decline in price and could result in us postponing or canceling a planned project or potential acquisition, or if it is not possible to cancel, to carry out the project or acquisition with negative economic impacts. Further, a reduction in natural gas, NGL or oil prices may lead our producing fields to be shut down and to be entered into the decommissioning phase earlier than estimated.
Our revenues, cash flows, operating results, profitability, dividends, future rate of growth and the carrying value of our gas and oil properties depend heavily on the prices we receive for natural gas, NGLs and oil sales. Commodity prices also affect our cash flows available for capital investments and other items, including the amount and value of our gas and oil reserves. In addition, we may face gas and oil property impairments if prices fall significantly. In light of the continuing increase in supply coming from the Utica and Marcellus shale plays of the Appalachian Basin, no assurance can be given that commodity prices will remain at levels which enable us to do business profitably or at levels that make it economically viable to produce from certain wells and any material decline in such prices could result in a reduction of our net production volumes and revenue and a decrease in the valuation of our production properties, which could negatively impact our business, results of operations, financial condition, cash flows or prospects.
We conduct our business in a highly competitive industry.
The gas and oil industry is highly competitive. The key areas in which we face competition include:
•
engagement of third-party service providers whose capacity to provide key services may be limited;
•
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:
22
•
higher than anticipated prices for the acquisition of licenses or assets;
•
the hiring by competitors of key management or other personnel; and
•
restrictions on the availability of equipment or services.
If we are unsuccessful in competing against other companies, our business, results of operations, financial condition, cash flows or prospects could be materially adversely affected.
We may experience delays in production, marketing and transportation.
Various production, marketing and transportation conditions may cause delays in natural gas, NGLs and oil production and adversely affect our business. For example, the gas gathering systems that we own connect to other pipelines or facilities which are owned and operated by third parties. These pipelines and other midstream facilities and others upon which we rely may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage. In periods where NGL prices are high, we benefit greatly from the ability to process NGLs. Our largest processor of NGLs is the MarkWest Energy Partners, L.P., (“MarkWest”) plant located in Langley, Kentucky. If we were to lose the ability to process NGLs at MarkWest’s plant during a period of high pricing, our revenues would be negatively impacted. As a short-term measure, we could divert the natural gas through other pipeline routes; however, certain pipeline operators would eventually decline to transport the gas due to its liquid content at a level that would exceed tariff specifications for those pipelines. The lack of available capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells. Any significant changes affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay our production, which could negatively impact our business, results of operations, financial condition, cash flows or prospects.
We face production risks and hazards that may affect our ability to produce natural gas, NGLs and oil at expected levels, quality and costs that may result in additional liabilities to us.
Our natural gas and oil production operations are subject to numerous risks common to our industry, including, but not limited to, premature decline of reservoirs, incorrect production estimates, invasion of water into producing formations, geological uncertainties such as unusual or unexpected rock formations and abnormal geological pressures, low permeability of reservoirs, contamination of natural gas and oil, blowouts, oil and other chemical spills, explosions, fires, equipment damage or failure, challenges relating to transportation, pipeline infrastructure, natural disasters, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, shortages of skilled labor, delays in obtaining regulatory approvals or consents, pollution and other environmental risks.
If any of the above events occur, environmental damage, including biodiversity loss or habitat destruction, injury to persons or property and other species and organisms, loss of life, failure to produce natural gas, NGLs and oil in commercial quantities or an inability to fully produce discovered reserves could result. These events could also cause substantial damage to our property or the property of others and our reputation and put at risk some or all of our interests in licenses, which enable us to produce, and could result in the incurrence of fines or penalties, criminal sanctions potentially being enforced against us and our management, as well as other governmental and third-party claims. Consequent production delays and declines from normal field operating conditions and other adverse actions taken by third parties may result in revenue and cash flow levels being adversely affected.
Moreover, should any of these risks materialize, we could incur legal defense costs, remedial costs and substantial losses, including those due to injury or loss of life, human health risks, severe damage to or destruction of property, natural resources and equipment, environmental damage, unplanned production outages, clean-up responsibilities, regulatory investigations and penalties, increased public interest in our operational performance and suspension of operations, which could negatively impact our business, results of operations, financial condition, cash flows or prospects.
The levels of our natural gas and oil reserves and resources, their quality and production volumes may be lower than estimated or expected.
The reserves data contained in this registration statement have been audited by Netherland, Sewell & Associates, Inc. (“NSAI”) unless stated otherwise. The standards utilized to prepare the reserves information
23
that has been extracted in this document may be different from the standards of reporting adopted in other jurisdictions. Investors, therefore, should not assume that the data found in the reserves information set forth in this prospectus is directly comparable to similar information that has been prepared in accordance with the reserve reporting standards of other jurisdictions, such as the United Kingdom.
In general, estimates of economically recoverable natural gas, NGLs and oil reserves are based on a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological, geophysical and engineering estimates (which have inherent uncertainties), historical production from the properties or analogous reserves, the assumed effects of regulation by governmental agencies and estimates of future commodity prices, operating costs, gathering and transportation costs and production related taxes, all of which may vary considerably from actual results.
Underground accumulations of hydrocarbons cannot be measured in an exact manner and estimates thereof are a subjective process aimed at understanding the statistical probabilities of recovery. Estimates of the quantity of economically recoverable natural gas and oil reserves, rates of production and, where applicable, the timing of development expenditures depend upon several variables and assumptions, including the following:
•
production history compared with production from other comparable producing areas;
•
quality and quantity of available data;
•
interpretation of the available geological and geophysical data;
•
effects of regulations adopted by governmental agencies;
•
future percentages of sales;
•
future natural gas, NGLs and oil prices;
•
capital investments;
•
effectiveness of the applied technologies and equipment;
•
effectiveness of our field operations employees to extract the reserves;
•
natural events or the negative impacts of natural disasters;
•
future operating costs, tax on the extraction of commercial minerals, development costs and workover and remedial costs; and
•
the judgment of the persons preparing the estimate.
As all reserve estimates are subjective, each of the following items may differ materially from those assumed in estimating reserves:
•
the quantities and qualities that are ultimately recovered;
•
the timing of the recovery of natural gas and oil reserves;
•
the production and operating costs incurred;
•
the amount and timing of development expenditures, to the extent applicable;
•
future hydrocarbon sales prices; and
•
decommissioning costs and changes to regulatory requirements for decommissioning.
Many of the factors in respect of which assumptions are made when estimating reserves are beyond our control and therefore these estimates may prove to be incorrect over time. Evaluations of reserves necessarily involve multiple uncertainties. The accuracy of any reserves evaluation depends on the quality of available information and natural gas, NGLs and oil engineering and geological interpretation. Furthermore, less historical well production data is available for unconventional wells because they have only become technologically viable in the past twenty years and the long-term production data is not always sufficient to determine terminal decline rates. In comparison, some conventional wells in our portfolio have been productive for a much longer time. As a result, there is a risk that estimates of our shale reserves are not as
24
reliable as estimates of the conventional well reserves that have a longer historical profile to draw on. Interpretation, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserves and resources data. Moreover, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material.
If the assumptions upon which the estimates of our natural gas and oil reserves prove to be incorrect or if the actual reserves available to us (or the operator of an asset in we have an interest) are otherwise less than the current estimates or of lesser quality than expected, we may be unable to recover and produce the estimated levels or quality of natural gas, NGLs or oil set out in this document and this may materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
The PV-10, will not necessarily be the same as the current market value of our estimated natural gas, NGL and oil reserves.
You should not assume that the present value of future net cash flows from our reserves is the current market value of our estimated natural gas, NGL and oil reserves. Actual future net cash flows from our natural gas and oil properties will be affected by factors such as:
•
actual prices we receive for natural gas, NGL and oil;
•
actual cost of development and production expenditures;
•
the amount and timing of actual production;
•
transportation and processing; and
•
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of our natural gas and oil properties will affect the timing and amount of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Actual future prices and costs may differ materially from those used in the present value estimate. See the subsection titled “Presentation of Financial Information—Use of Non-IFRS Measures” for additional information regarding our use of PV-10.
We may face unanticipated increased or incremental costs in connection with decommissioning obligations such as plugging.
In the future, we may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for the processing of natural gas and oil reserves. With regards to plugging, we are party to agreements with regulators in the states of Ohio, West Virginia, Kentucky and Pennsylvania, our four largest wellbore states, setting forth plugging and abandonment schedules spanning a period ranging from 10 to 15 years. We will incur such decommissioning costs at the end of the operating life of some of our properties. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques, the shortage of plugging vendors, difficult terrain or weather conditions or experience at other production sites. The expected timing and amount of expenditure can also change, for example, in response to changes in reserves, wells losing commercial viability sooner than forecasted or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The use of other funds to satisfy such decommissioning costs may impair our ability to focus capital investment in other areas of our business, which could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.
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
25
processing technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other 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. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost or even at all given the personnel resources that are available to us. In addition to implementing new accounting and royalty management software, we are also implementing technology that aims to improve field data capture for our, as of December 31, 2022, approximately 77,598 gross productive wells so as to grant efficient access to information for decision-making. These efforts to upgrade our enterprise technology represent a significant undertaking and may have unforeseen adverse consequences. If one or more of the technologies used now or in the future were to become obsolete, our business, results of operations, financial condition, cash flows or prospects could be materially adversely affected if competitors gain a material competitive advantage.
The 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 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:
•
demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas business;
•
a decrease in international demand for natural gas or NGLs produced in the United States could adversely affect the pricing for such products, which could adversely affect our results of operations and liquidity;
•
the tightening of credit or lack of credit availability to our customers could adversely affect our liquidity, as our ability to receive payment for our products sold and delivered depends on the continued creditworthiness of our customers;
•
our ability to refinance our Credit Facility may be limited and the terms on which we are able to do so may be less favorable to us depending on the strength of the capital markets or our credit ratings;
26
•
our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our natural gas reserves;
•
increased capital markets scrutiny of oil and gas companies may lead to increased costs of capital or lack of credit availability; and
•
a decline in our creditworthiness may require us to post letters of credit, cash collateral, or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.
In addition, the 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 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
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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 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 such as TC Energy (formerly TransCanada), Enbridge, CNX, Dominion Energy Transmission and MarkWest that we do not control and/or, in each case, are subject to tariff charges that we do not control.
A significant portion of our production passes through third-party owned and controlled infrastructure. If these third-party pipelines or liquids processing facilities experience any event that causes an interruption in operations or a shut-down such as mechanical problems, an explosion, adverse weather conditions, a terrorist attack or labor dispute, our ability to produce or transport natural gas could be severely affected. For example, we have an agreement with MarkWest where approximately 51% of the NGLs we sold during the year ending December 31, 2022 were processed at MarkWest’s facility in Kentucky. Any material decrease in our ability to process or transport our natural gas through third-party infrastructure such as MarkWest’s could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
Our use of third-party infrastructure may be subject to tariff charges. Although we seek to manage our flow via our midstream infrastructure, we may not always be able to avoid higher tariffs or basis blowouts due to the lack of interconnections. In such instances, the tariff charges can be substantial and the cost is not subject to our direct control, although we may have certain contractual or governmental protections and rights. Generally, the operator of the gathering or transmission pipelines sets these tariffs and expenses on a cost sharing basis according to our proportionate hydrocarbon through-put of that facility. A provisional tariff rate is applied during the relevant year and then finalized the following year based on the actual final costs and final through-put volumes. Such tariffs are dependent on continued production from assets owned by third parties and, may be priced at such a level as to lead to production from our assets ceasing to be
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economic and thus may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
Furthermore, our use of third-party infrastructure exposes us to the possibility that such infrastructure will cease to be operational or be decommissioned and therefore require us to source alternative export routes and/or prevent economic production from our assets. This could also have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
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.
We and our offtakers rely, and any future offtakers will rely, upon the availability of pipeline and storage capacity systems, including such infrastructure systems that are owned and operated by third parties. As a result, we may be unable to access or source alternatives for the infrastructure and systems which we currently use or plan to use, or otherwise be subject to interruptions or delays in the availability of infrastructure and systems necessary for the delivery of our natural gas, NGLs and oil to commercial markets. In addition, such infrastructure may be close to its design life and decisions may be taken to decommission such infrastructure or perform life extension work to maintain continued operations. Any of these events could result in disruptions to our projects and thereby impact our ability to deliver natural gas, NGLs and oil to commercial markets and/or may increase our costs associated with the production of natural gas, NGLs and oil reliant upon such infrastructure and systems. Further, our offtakers could become subject to increased tariffs imposed by government regulators or the third-party operators or owners of the transportation systems available for the transport of our natural gas, NGLs and oil, which could result in decreased offtaker demand and downward pricing pressure.
If we are unable to access infrastructure systems facilitating the delivery of our natural gas, NGLs and oil to commercial markets due to our contractors or primary offtakers being unable to access the necessary equipment or transportation systems, our operations will be adversely affected. If we are unable to source the most efficient and expedient infrastructure systems for our assets then delivery of our natural gas, NGLs and oil to the commercial markets may be negatively impacted, as may our costs associated with the production of natural gas, NGLs and oil reliant upon such infrastructure and systems.
A proportion of our equipment has substantial prior use and significant expenditure may be required to maintain operability and operations integrity.
A part of our business strategy is to optimize or refurbish producing assets where possible to maximize the efficiency of our operations while avoiding significant expenses associated with purchasing new equipment. Our producing assets and midstream infrastructure require ongoing maintenance to ensure continued operational integrity. For example, some older wells may struggle to produce suitable line pressure and will require the addition of compression to push natural gas. Despite our planned operating and capital expenditures, there can be no guarantee that our assets or the assets we use will continue to operate without fault and not suffer material damage in this period through, for example, wear and tear, severe weather conditions, natural disasters or industrial accidents. If our assets, or the assets we use, do not operate at or above expected efficiencies, we may be required to make substantial expenditures beyond the amounts budgeted. Any material damage to these assets or significant capital expenditure on these assets for
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improvement or maintenance may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects. In addition, as with planned operating and capital expenditure, there is no guarantee that the amounts expended will ensure continued operation without fault or address the effects of wear and tear, severe weather conditions, natural disasters or industrial accidents. We cannot guarantee that such optimization or refurbishment will be commercially feasible to undertake in the future and we cannot provide assurance that we will not face unexpected costs during the optimization or refurbishment process.
We depend on our directors, key members of management, independent experts, technical and operational service providers and on our ability to retain and hire such persons to effectively manage our growing business.
Our future operating results depend in significant part upon the continued contribution of our directors, key senior management and technical, financial and operations personnel. Management of our growth will require, among other things, stringent control of financial systems and operations, the continued development of our control environment, the ability to attract and retain sufficient numbers of qualified management and other personnel, the continued training of such personnel and the presence of adequate supervision.
In addition, the personal connections and relationships of our directors and key management are important to the conduct of our business. If we were to unexpectedly lose a member of our key management or fail to maintain one of the strategic relationships of our key management team, our business, results of operations, financial condition, cash flows or prospects could be materially adversely affected. In particular, we are highly dependent on our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr. Acquisitions are a key part of our strategy, and Mr. Hutson has been instrumental in sourcing them and securing their financing. Furthermore, as our founder, Mr. Hutson is strongly associated with our success, and if he were to cease being the Chief Executive Officer, perception of our future prospects may be diminished. 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
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seismic events in certain areas of the country, including the states of West Virginia, Ohio and Kentucky in the Appalachian Basin as well as Oklahoma, Texas and Louisiana in our Central Region. Certain states, including those located in the Appalachian Basin have adopted, or are considering adopting, laws and regulations that may restrict or prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic events have occurred to restrict or suspend disposal well permits or operations or impose certain conditions related to disposal well construction, monitoring, or operations. Any of these developments could increase our cost to dispose of our produced water.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to the authority under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), as amended by the Pipeline Safety Improvement Act of 2002 (“PSIA”), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPESA”) and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact HCAs;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of pipeline integrity testing, but the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the safe and reliable operation of our pipelines.
The 2011 Pipeline Safety Act amends the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. Additionally, pursuant to one of the requirements of the 2011 Pipeline Safety Act, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain gas lines, extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond HCAs to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as five dwellings within the potential impact area and require gas pipelines installed before 1970 that were exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”). Other requirements proposed by PHMSA under the rulemaking include: reporting to PHMSA in the event of certain MAOP exceedances; strengthening PHMSA integrity management requirements; considering seismicity in evaluating threats to a pipeline; conducting hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and using more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on gathering lines. In January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management
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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 requireds that PHMSA publish periodic updates on the status of those mandates outstanding from the 2011 Pipeline Safety Act PHMSA has recently published three parts of its so-called “Mega Rule”, including rules focused on: the safety of gas transmission pipelines, the safety of hazardous liquid pipelines and enhanced emergency order procedures. PHMSA finalized the first part of the rule, which primarily addressed maximum operating pressure and integrity management near HCAs for onshore gas transmission pipelines, in October 2019. PHMSA finalized the second part of the rule, which extended federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures, in November 2021. PHMSA published the final of the three components of the Mega Rule in August 2022, which took effect in May 2023. The final rule applies to onshore gas transmission pipelines, and clarifies integrity management regulations, expands corrosion control requirements, mandates inspection after extreme weather events, and updates existing repair criteria for both HCA and non-HCA pipelines. Finally, PHMSA published a Notice of Proposed Rulemaking regarding more stringent gas pipeline leak detection and repair requirements to reduce methane 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. 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.
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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.
We are actively monitoring the situation in Ukraine and assessing its impact on our business. To date we have not experienced any material interruptions in our infrastructure, supplies, technology systems or networks needed to support our operations given our operating areas are exclusively located within the Central Region and the Appalachian Basins of the U.S. We have no way to predict the progress or outcome of the conflict in Ukraine or its impacts in Ukraine, Russia or Belarus as the conflict, and any resulting government reactions, are rapidly developing and beyond our control. The extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have substantial impact on the global economy and our business for an unknown period of time. Any of the aforementioned factors could affect our business, financial condition and results of operations. Any such disruptions may also magnify the impact of other risks described in this prospectus.
Risks Relating to our Financing, Acquisitions, Investment and Indebtedness
Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability to enter into future debt financing.
Inflation can adversely affect us by increasing costs of materials, equipment, labor and other services. In addition, inflation is often accompanied by higher interest rates. Continued inflationary pressures could impact our profitability. Though we believe that the rates of inflation in recent years, including the 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 the subsection titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt”) and as of June 30, 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
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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”) and 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”). Our ability to complete future acquisitions will depend on us being able to identify suitable acquisition candidates and negotiate favorable terms for their acquisition, in each case, before any attractive candidates are purchased by other parties such as private equity firms, some of whom have substantially greater financial and other resources than we do. We may face competition for attractive acquisition targets that may also increase the price of the target business. As a result, there is no assurance that we will always be able to source and execute acquisitions in the future at attractive valuations.
Furthermore, to further the Company’s growth, we have made further acquisitions outside the Appalachian Basin, a region in which we have developed our operational experience into the Bossier Shale, the Haynesville Shale, the Barnett Shale Play, and the Cotton Valley and Mid-Continent producing areas. Accordingly, an acquisition in a new area in which we lack experience may present unanticipated risks and challenges that were not accounted for or previously experienced. Ordinarily, our due diligence efforts are focused on higher valued and material properties or assets. Even an in-depth review of all properties and records may not reveal all existing or potential problems, nor will such review always permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Generally, physical inspections are not performed on every well or facility, and structural or environmental problems are not necessarily observable even when an inspection is undertaken.
There can be no assurance that our prior acquisitions or any other potential acquisition will perform operationally as anticipated or be profitable. We could fail to appropriately value any acquired business and the value of any business, company or property that we acquire or invest in may actually be less than the amount paid for it or its estimated production capacity. We may be required to assume pre-closing liabilities with respect to an acquisition, including known and unknown title, contractual, and environmental and decommissioning liabilities, and may acquire interests in properties on an “as is” basis without recourse to the seller of such interest or the seller may have limited resources to provide post-sale indemnities.
In addition, successful acquisitions of gas and oil assets require an assessment of a number of factors, including estimates of recoverable reserves, the time of recovering reserves, exploration potential, future natural gas, NGLs and oil prices and operating costs. Such assessments are inexact, and we cannot guarantee that we make these assessments with a high degree of accuracy. In connection with assessments, we perform a review of the acquired assets. However, such a review will not reveal all existing or potential problems. Furthermore, review may not permit us to become sufficiently familiar with the assets to fully assess their deficiencies and capabilities.
Integrating operations, technology, systems, management, back office personnel and pre- or post-completion costs for future acquisitions may prove more difficult or expensive than anticipated, thereby rendering the value of any company or assets acquired less than the amount paid. We may also take on unexpected liabilities which are uncapped, have to undertake unanticipated capital expenditures in connection with a new acquisition or provide uncapped liabilities in connection with the purchase and sale of assets, which are customary in such agreements. The integration of acquired businesses or assets requires significant time and effort on the part of our management. Following such integration efforts, prior acquisitions may still not achieve the level of financial or operational performance that was anticipated when they were acquired. In addition, the integration of new acquisitions can be difficult and disrupt our own business because our operational and business culture may differ from the cultures of the acquired businesses, unpopular cost-cutting measures may be required, internal controls may be more difficult to maintain and control over
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cash flows and expenditures may be difficult to establish. If we encounter any of the foregoing issues in relation to one of our acquisitions this could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of businesses that complement or expand our current business. However, we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
Our Credit Facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
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 4,784,275 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 other plans for an offering of ordinary shares, it is possible that we may decide to offer additional ordinary shares in the future. Subject to any applicable pre-emption rights, any future issues of ordinary shares by the Company may have a dilutive effect on the holdings of shareholders and could have a material adverse effect on the market price of ordinary shares as a whole.
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Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our Credit Facility contains a number of significant covenants that may limit our ability to, among other things:
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incur additional indebtedness;
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incur liens;
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sell assets;
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make certain debt payments;
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enter into agreements that restrict or prohibit the payment of dividends;
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limits our subsidiaries’ ability to make certain payments with respect to their equity, based on the pro forma effect thereof on certain financial ratios, which would be the source of distributable profits from which we may issue a dividend; and
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conduct hedging activities.
In addition, our Credit Facility requires us to maintain compliance with certain financial covenants.
We may also be prevented from taking advantage of business opportunities that arise because of the limitations from the restrictive covenants under our Credit Facility. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities.
A breach of any covenant in our Credit Facility will result in a default under the agreement and may result in an event of default under the Credit Facility if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under our Credit Facility and in an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
Any significant reduction in our borrowing base under our Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Our Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, unilaterally determine based upon our reserve reports for the applicable period and other data and reports. Such determinations will be made on a regular basis semi-annually (each a “Scheduled Redetermination”) and at the option of the lenders with more than 66.6% of the loans and commitments under the Credit Facility, no more than one time in between each Scheduled Redetermination. As of the date hereof, our borrowing base is $375 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
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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 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 the date of this prospectus, we had $ 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 loss 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.
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Our price hedging strategy and future hedging transactions will be determined at our discretion, subject to the terms of certain agreements governing our indebtedness. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our natural gas, NGL and oil revenues becoming more sensitive to commodity price fluctuations.
The failure of our hedge counterparties to meet their obligations to us may adversely affect our financial results.
An attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by the counterparty to these derivative contracts when they become due would have a material adverse effect on our results of operations, financial condition, cash flows and prospects.
We may not be able to enter into commodity derivatives on favorable terms or at all.
To achieve a more predictable cash flow, we employ a hedging strategy involving opportunistically hedging a majority of our first two years of production as well as hedging a significant percentage of production beyond our first two years of forecasted production. If we are unable to maintain sufficient hedging capacity with our counterparties, we could have greater exposure to changes in commodity prices and interest rates, which could have a material adverse impact on our business, results of operations, financial condition, cash flows or prospects.
Risks Relating to Legal, Tax, Environmental and Regulatory Matters
We are subject to regulation and liability under environmental, health and safety regulations, the violation of which may affect our financial condition and operations.
We operate in an industry that has certain inherent hazards and risks, and consequently we are subject to stringent and comprehensive laws and regulations, especially with regard to the protection of health, safety and the environment. For example, we are subject to laws and regulations related to occupational safety and health, hydraulic fracturing activities, air emissions, soil and water quality, the protection of threatened and endangered plant and animal species, biodiversity and ecosystems, and the safety of our assets and employees. Although we believe that we have adequate procedures in place to mitigate operational risks, there can be no assurances that these procedures will be adequate to address every potential health, safety and environmental hazard, and a failure to adequately mitigate risks may result in loss of life, injury, or adverse impacts on the health of employees, contractors and third-parties or the environment. Any failure by us or one of our subcontractors, whether inadvertent or otherwise, to comply with applicable legal or regulatory requirements may give rise to civil, administrative and/or criminal liabilities, civil fines and penalties, delays or restrictions in acquiring or disposing of assets and/or delays in securing or maintaining required permits, licenses and approvals. Further, a lack of regulatory compliance may lead to denial, suspension, or termination of permits, licenses, or approvals that are required to operate our sites or could result in other operational restrictions or obligations. Our health, safety and environmental policiesy 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
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granted by relevant authorities or applications for the same and operations may be subject to other administrative or judicial challenges.
In addition, under certain environmental laws and regulations, we could be subject to joint and several strict liability for the removal or remediation of previously released materials, pollution, or property contamination regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties on or adjacent to well sites and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases of pollutants or contaminants could expose us to significant liabilities that could have a material adverse effect on our business, financial condition and results of operations.
We incur, and expect to continue to incur, capital and operating costs in an effort to comply with increasingly complex operational health and safety and environmental laws and regulations. New laws and regulations, the imposition of more stringent requirements in permits and licenses, increasingly strict enforcement of, or new interpretations of, existing laws, regulations and permits and licenses, or the discovery of previously unknown contamination or hazards may require further costly expenditures to, for example:
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modify operations, including an increase in plugging and abandonment operations;
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install or upgrade pollution or emissions control equipment;
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perform site clean ups, including the remediation and reclamation of gas and oil sites;
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curtail or cease certain operations;
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provide financial securities, bonds, and/or take out insurance; or
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pay fees or fines or make other payments for pollution, discharges to the environment or other breaches of environmental or health and safety requirements or consent agreements with regulatory agencies.
We cannot predict with any certainty the full impact of any new laws, regulations, or policies on our operations or on the cost or availability of insurance to cover the risks associated with such operations. The costs of such measures and liabilities related to potential operational health and safety or environmental risks associated with the Company may increase, which could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects. In addition, it is not possible to predict what future operational health and safety or environmental laws and regulations will be enacted or how current or future operational, health, safety or environmental laws and regulations will be applied or enforced. We may have to incur significant expenditure for the installation and operation of additional systems and equipment for monitoring and carry out remedial measures in the event that operational health and, safety and environmental regulations become more stringent or costly reform is implemented by regulators. Any such expenditure may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects. No assurance can be given that compliance with occupational health and safety and environmental laws or regulations in the regions where we operate will not result in a curtailment of production or a material increase in the cost of production or development activities.
Increasing attention to ESG matters may impact our business and financial results.
Increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ board of directors and promoting the use of alternative forms of energy. These activities may result in demand shifts for oil and natural gas products and additional governmental investigations and private ligation against us. In addition, a failure to comply with evolving investor or customer expectations and standards
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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 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
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the shale layers of the property will typically be conditioned on the ongoing productivity of conventional wells on the property. Furthermore, the shale rights may be owned by a third party, and in such instances, we will enter into a joint use agreement with the third party. This joint use agreement may stipulate that in consideration for permission to operate the conventional wells, we are to use reasonable efforts to maintain production so that the third party retains the shale licenses. If we fail to maintain production in the conventional wells, under the joint use agreement, we may be liable to the third party for replacing the lost land rights. The relevant authorities are typically authorized to, and do from time to time, inspect to verify compliance by us or our commercial partners, as applicable, with relevant laws and the licenses or the agreements pursuant to which we conduct our business. There can be no assurance that the views of the relevant government agencies regarding the development of the fields that we operate or the compliance with the terms of the licenses pursuant to which we conduct such operations will coincide with our views, which might lead to disagreements that may not be resolved.
The suspension, revocation, withdrawal or termination of any of the permits, licenses or related agreements pursuant to which we may conduct business, as well as any delays in the continuous development of or production at our fields caused by the issues detailed above could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects. In addition, failure to comply with the obligations under the permits, licenses or agreements pursuant to which we conduct business, whether inadvertent or otherwise, may lead to fines, penalties, restrictions, enforcement actions brought by governmental authorities, withdrawal of licenses and termination of related agreements.
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
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systems, misappropriate proprietary information and/or cause interruptions to our services, and we expect to continue to face similar threats in the future. We cannot guarantee that we will be able to successfully prevent all attacks in the future. Such future attacks could include hackers obtaining access to our systems, the introduction of malicious computer code or denial of service attacks. If an actual or perceived breach of our network security occurs, it could adversely affect our business or reputation, and may expose us to the loss of information, litigation and possible liability. An actual security breach could also impair our ability to operate our business and provide products and services to our customers. Additionally, malicious attacks, including cyber-attacks, may damage our assets, prevent production at our producing assets and otherwise significantly affect corporate activities. For example, we utilize electronic monitoring of meters and flow rate devices to monitor pressure build-up in our production wells. If there were a cyber-attack that penetrated our monitoring systems such that they provided false readings, this could result in an unknown pressure build-up, creating a dangerous situation which could end up in an explosion. As techniques used to obtain unauthorized access to or to sabotage systems change frequently and may not be known until launched against us or our third-party service providers, we may be unable to anticipate or implement adequate measures to protect against these attacks and our service providers may likewise be unable to do so. Such an outcome would have a material adverse impact on our business, results of operations, financial condition, cash flows or prospects.
In addition, confidential or financial payment information that we maintain may be subject to misappropriation, theft and deliberate or unintentional misuse by current or former employees, third-party contractors or other parties who have had access to such information. Any such misappropriation and/or misuse of our information could result in the Company, among other things, being in breach of certain data protection requirements and related legislation as well as incurring liability to third parties. We expect that we will need to continue closely monitoring the accessibility and use of confidential information in our business, educate our employees and third-party contractors about the risks and consequences of any misuse of confidential information and, to the extent necessary, pursue legal or other remedies to enforce our policies and deter future misuse. If our confidential information is misappropriated, stolen or misused as a result of a disruption to our website or internal systems this could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.
Although we maintain insurance to protect against losses resulting from certain of data protection breaches and cyber-attacks, our coverage for protecting against such risks may not be sufficient.
Our operations are subject to the risk of litigation.
From time to time, we may be subject, directly or indirectly, to litigation arising out of our operations and the regulatory environments in our areas of operations. Historically, categories of litigation that we have faced included actions by royalty owners over payment disputes, personal injury claims and property related claims, including claims over property damage, trespass or nuisance. Although we currently face no material litigation for which we are not sufficiently indemnified or insured, damages claimed under such litigation in the future may be material or may be indeterminate, and the outcome of such litigation, if determined adversely to us, could individually or in the aggregate, be reasonably expected to have a material and adverse effect on our business, financial position or results of operations. While we assess the merits of each lawsuit and defend ourselves accordingly, we may be required to incur significant expenses or devote significant resources to defend against such litigation. In addition, the adverse publicity surrounding such claims may have a material adverse effect on our business.
We are subject to certain tax risks.
Any change in our tax status or in taxation legislation in the United Kingdom or the United States could affect our ability to provide returns to shareholders. Statements in this document concerning the taxation of holders of our 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
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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 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.
Risks Relating to Our Ordinary Shares and This Offering
The price of our ordinary shares may be volatile and may fluctuate due to factors beyond our control.
The initial public offering price for the ordinary shares will be determined through negotiations between the underwriters and us, and may vary from the market price of our ordinary shares following this offering. If you purchase ordinary shares in this offering, you may not be able to resell those ordinary shares at or above the initial public offering price. The market price of our ordinary shares may fluctuate significantly due to a variety of factors, including:
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operating results that vary from our financial guidance or the expectations of securities analysts and investors;
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the financial performance of the major end markets that we target;
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the operating and securities price performance of companies that investors consider to be comparable to us;
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announcements of strategic developments, acquisitions and other material events by us or our competitors;
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failure to meet or exceed financial estimates and projections of the investment community or that we provide to the public;
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issuance of new or updated research or reports by securities analysts;
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changes in government regulations;
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financing or other corporate transactions;
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the loss of any of our key personnel;
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sales of our ordinary shares by us, our executive officers and board members or our shareholders in the future;
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price and volume fluctuations in the overall stock market, including as a result of trends in the economy as a whole; and
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other events and factors, many of which are beyond our control.
These and other market and industry factors may cause the market price and demand for our ordinary shares to fluctuate substantially, regardless of our actual operating performance, which may limit or prevent investors from readily selling their ordinary shares and may otherwise negatively affect the liquidity of our ordinary shares. In the past, when the market price of a stock has been volatile, holders of that stock have sometimes instituted securities class action litigation against the issuer. If any of the holders of our ordinary shares were to bring such a lawsuit against us, we could incur substantial costs defending the lawsuit and the attention of our senior management would be diverted from the operation of our business. Any adverse determination in litigation could also subject us to significant liabilities.
There has been no public market in the United States for our ordinary shares prior to this offering, and an active market may not develop in which investors can resell our ordinary shares.
Prior to this offering, there has been no public market in the United States for our ordinary shares, 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 public offering price of our ordinary shares in the United States will be agreed upon between us and the underwriters 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 offering. Investors may not be able to sell their ordinary shares at or above the initial public offering price.
The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our 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.
We have broad discretion in the use of the net proceeds from this offering and may not use them effectively.
We will have broad discretion in the application of the net proceeds from this offering and could spend the proceeds in ways that do not improve our results of operations or enhance the value of our ordinary shares. Our failure to apply these funds effectively could result in financial losses or cause the price of our ordinary shares to decline. Pending their use, we may invest the net proceeds from this offering in a manner that does not produce income or that loses value.
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The dual listing of our ordinary shares following this offering may adversely affect the liquidity and value of our ordinary shares.
Following this offering 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 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.
We are an “emerging growth company,” and we cannot be certain if the reduced reporting requirements applicable to “emerging growth companies” will make our ordinary shares less attractive to investors.
We are an “emerging growth company,” as defined in the JOBS Act. For as long as we continue to be an emerging growth company, we may take advantage of exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. As an emerging growth company, we are required to report only two years of financial results and selected financial data in our initial public offering registration statement, as compared to three and five years, respectively, for comparable data reported by other public companies. We may take advantage of these exemptions until we are no longer an emerging growth company. We could be an emerging growth company for up to five years, although circumstances could cause us to lose that status earlier, including if the aggregate market value of our ordinary shares held by non-affiliates exceeds $700 million as of any June 30 (the end of our second fiscal quarter) before that time, in which case we would no longer be an emerging growth company as of the following December 31 (our fiscal year-end). We cannot predict if investors will find our ordinary shares less attractive because we may rely on these exemptions. If some investors find our ordinary shares less attractive as a result, there may be a less active trading market for our ordinary shares and the price of our ordinary shares may be more volatile.
We qualify as a foreign private issuer and, as a result, we will not be subject to U.S. proxy rules and will be subject to Exchange Act reporting obligations that, to some extent, are more lenient and less frequent than those of a U.S. domestic public company.
Upon the closing of this offering, we will report under the Exchange Act as a non-U.S. company with foreign private issuer status. Because we qualify as a foreign private issuer under the Exchange Act, we are exempt from certain provisions of the Exchange Act that are applicable to U.S. domestic public companies, including (i) the sections of the Exchange Act regulating the solicitation of proxies, consents or authorizations in respect of a security registered under the Exchange Act; (ii) the sections of the Exchange Act requiring insiders to file public reports of their stock ownership and trading activities and liability for insiders who profit from trades made in a short period of time; and (iii) the rules under the Exchange Act requiring the filing with the SEC of quarterly reports on Form 10-Q containing unaudited financial and other specified information, or current reports on Form 8-K, upon the occurrence of specified significant events. In addition, foreign private issuers are not required to file their annual report on Form 20-F until 120 days after the end of each fiscal year, while U.S. domestic issuers that are accelerated filers are required to file their annual report on Form 10-K within 75 days after the end of each fiscal year. Foreign private issuers also are exempt from Regulation Fair Disclosure, aimed at preventing issuers from making selective disclosures of material information. As a result of the above, you may not have the same protections afforded to shareholders of companies that are not foreign private issuers, some investors may find the 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
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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 the subsection titled “Management—Corporate Governance Practices and Foreign Private Issuer Status.”
We may lose our foreign private issuer status, which would then require us to comply with the Exchange Act’s domestic reporting regime and cause us to incur significant legal, accounting and other expenses.
As a foreign private issuer, we are not required to comply with all of the periodic disclosure and current reporting requirements of the Exchange Act applicable to U.S. domestic issuers. To the extent we no longer qualify as a foreign private issuer as of June 30, 2024 (the end of our second fiscal quarter in the fiscal year after this offering), we would be required to comply with all of the periodic disclosure and current reporting requirements of the Exchange Act applicable to U.S. domestic issuers as of July 1, 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 rules. The regulatory and compliance costs to us under U.S. securities laws if we are required to comply with the reporting requirements applicable to a U.S. domestic issuer may be significantly higher than the cost we would incur as a foreign private issuer. As a result, we expect that a loss of foreign private issuer status would increase our legal and financial compliance costs and would make some activities highly time consuming and costly. If we lose foreign private issuer status and are unable to comply with the reporting requirements applicable to a U.S. domestic issuer by the applicable deadlines, we would not be in compliance with applicable SEC rules or the rules of , which could cause investors could lose confidence in our public reports and could have a material adverse effect on the trading price of our 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.
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 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
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regulations of the SEC, to furnish a report by management on the effectiveness of our internal control over financial reporting in the second annual report following the completion of this offering. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. Assessing the effectiveness of our internal control over financial reporting will require significant documentation, testing and possible remediation. Testing and maintaining internal control over financial reporting may divert our management’s attention from other matters that are important to our business. While we remain an emerging growth company, we will not be required to include an audit report on internal control over financial reporting issued by our independent registered public accounting firm.
We may not be able to conclude on an annual basis that we have effective internal control over financial reporting or our independent registered public accounting firm may not issue an unqualified opinion on the effectiveness of our internal control over financial reporting. If either we are unable to conclude that we have effective internal control over financial reporting or our independent registered public accounting firm is unable to issue an unqualified opinion on the effectiveness of internal control over financial reporting, investors could lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our 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 and our emerging growth company status. As a result, we have not engaged our external auditors to perform an audit over our internal control over financial reporting, and our efforts to design and implement control activities may not be sufficient to prevent future material weaknesses from occurring. 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 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
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is provided by regulatory and governing bodies. This could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices.
Future sales, or the possibility of future sales, of a substantial number of our ordinary shares could adversely affect the price of our ordinary shares.
Future sales of a substantial number of our ordinary shares, or the perception that such sales will occur, could cause a decline in the market price of our ordinary shares. Based upon the number of shares outstanding as of , 2023, after giving effect to this offering, we will have ordinary shares outstanding. Our ordinary shares sold in this offering may be resold in the public market immediately without restriction, unless purchased by our affiliates. Upon completion of this offering, we will have ordinary shares outstanding, approximately of which will be subject to day lock-up agreements entered into by our directors and officers and certain of our shareholders described in the sections titled “Shares Eligible for Future Sale” and “Underwriting.” The representatives of the underwriters may, in their sole discretion, release all or any portion of the equity securities subject to the lock-up agreements prior to the expiration of the lock-up agreements. If, after the end of such lock-up agreements, these shareholders sell substantial amounts of ordinary shares in the public market, or the market perceives that such sales may occur, the market price of our ordinary shares and our ability to raise capital through an issue of equity securities in the future could be adversely affected.
If you purchase ordinary shares in this offering, you will suffer immediate dilution of your investment.
We expect the initial public offering price of our ordinary shares in this offering to be substantially higher than the net tangible book value per ordinary share prior to this offering. Therefore, if you purchase ordinary shares in this offering, you will pay a price per share that substantially exceeds our net tangible book value per share after this offering. To the extent outstanding options are exercised for ordinary shares, you may experience further dilution. Based on the assumed initial public offering price of $ per ordinary share, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on LSE of £ on , 2023 (based on an assumed exchange rate of £1.00 to $1. ), you will experience immediate dilution of $ per ordinary share, representing the difference between our net tangible book value per ordinary share and per ordinary share after giving effect to this and the assumed offering price. See the section titled “Dilution.”
Because we may not pay any cash dividends on our 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 consistently declared dividends on our ordinary shares, in the future, our board of directors may decide, in its discretion, not to declare and pay dividends. Further, the Company’s Credit Facility contains a restricted payment covenant that limits its subsidiaries’ ability to make certain payments with respect to their equity, based on the pro forma effect thereof on certain financial ratios, which would be the source of distributable profits from which we may issue a dividend. Consequently, capital appreciation, if any, on our ordinary shares may be your sole source of gains, and you will suffer a loss on your investment if you are unable to sell your ordinary shares at or above the offering price. See the section titled “Dividend Policy.”
There is no guarantee that we will continue to pay dividends on our ordinary shares in the future.
Our dividend policy is dependent upon our financial condition, cash requirements, future prospects, compliance with the financial covenants and restricted payments covenant in the Company’s Credit Facility, profits available for distribution and other factors deemed to be relevant at the time and on the continued health of the markets in which we operate. While our dividend policy reflects our current and future expectation of future cash flow generation potential, there can be no guarantee that we will continue to pay dividends in the future on our ordinary shares.
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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 the subsection titled “Description of Share Capital and Articles of Association—Differences in Corporate Law” in this prospectus for a description of the principal differences between the provisions of the Companies Act 2006 applicable to us and, for example, the Delaware General Corporation Law relating to shareholders’ rights and protections.
Claims of U.S. civil liabilities may not be enforceable against us.
We are incorporated under the laws of the United Kingdom. In addition, certain of our directors and officers reside outside the United States. As a result, it may not be possible for investors to effect service of process within the United States upon such persons or to enforce judgments obtained in U.S. courts against them or us, including judgments predicated upon the civil liability provisions of the U.S. federal securities laws.
The United States and the United Kingdom do not currently have a treaty providing for recognition and enforcement of judgments (other than arbitration awards) in civil and commercial matters. Consequently, a final judgment for payment given by a court in the United States, whether or not predicated solely upon U.S. securities laws, would not automatically be recognized or enforceable in the United Kingdom. In addition, uncertainty exists as to whether UK courts would entertain original actions brought in the UK against us or our directors or senior management predicated upon the securities laws of the United States or any state in the United States. Provided that certain requirements are met, a final and conclusive monetary judgment for a definite sum obtained against us in U.S. courts (that is not a sum payable in respect of taxes or similar charges or in respect of a fine or a penalty), would be treated by the courts of the UK as a cause of action in itself and sued upon as a debt at common law without any retrial of the issue. Whether the relevant requirements are met in respect of a judgment based upon the civil liability provisions of the U.S. securities laws, including whether the award of monetary damages under such laws would constitute a penalty, is an issue for the court making such decision. If a UK court gives judgment for the sum payable under a U.S. judgment, the UK judgment will be enforceable by methods generally available for this purpose. These methods generally permit the UK court discretion to prescribe the manner of enforcement.
As a result, U.S. investors may not be able to enforce against us or our executive officers, board of directors or certain experts named herein who are residents of the United Kingdom or countries other than the United States any judgments obtained in U.S. courts in civil and commercial matters, including judgments under the U.S. federal securities laws.
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.
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements that are based on our management’s beliefs and assumptions and on information currently available to our management. Some of the statements under the sections titled “Prospectus Summary,” “Risk Factors,” “Use of Proceeds,” “Dividend Policy,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” and elsewhere in this prospectus contain forward-looking statements. In some cases, you can identify forward-looking statements by the following words: “may,” “might,” “will,” “could,” “would,” “should,” “expect,” “plan,” “anticipate,” “intend,” “seek,” “believe,” “estimate,” “predict,” “potential,” “continue,” “contemplate,” “possible” or the negative of these terms or other comparable terminology, although not all forward-looking statements contain these words. Forward-looking statements are not guarantees of performance. We have based forward-looking statements in this prospectus on our current expectations and beliefs about future developments and their potential effect on us.
These statements involve risks, uncertainties and other factors that may cause our actual results, levels of activity, performance or achievements to be materially different from the information expressed or implied by these forward-looking statements. Although we believe that we have a reasonable basis for each forward-looking statement contained in this prospectus, we caution you that these statements are based on a combination of facts and factors currently known by us and our projections of the future, about which we cannot be certain. Forward-looking statements contained in this prospectus are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties (some of which are beyond our control) and assumptions that could cause our actual results to differ materially from our historical experience and present expectations or projections. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements. Known material factors that could cause actual results to differ from those expressed in or implied by forward-looking statements contained or incorporated in this prospectus are described under “Risk Factors” and in other sections of this prospectus. Such factors include, but are not limited to:
•
declines in, the sustained depression of, or increased volatility in the prices we receive for our natural gas, oil and NGLs, or increases in the differential between index natural gas, oil and NGL prices and prices received;
•
risks related to and the effects of actual or anticipated pandemics such as the COVID-19 pandemic; uncertainties about the estimated quantities of natural gas, oil and NGL reserves;
•
operating risks, including, but not limited to, risks related to properties where we do not serve as the operator;
•
the adequacy of our capital resources and liquidity, including, but not limited to, access to additional borrowing capacity under our Credit Facility and the ability to obtain future financing on commercially reasonable terms or at all;
•
the effects of government regulation, permitting and other legal requirements, including, but not limited to, new legislation;
•
the effects of environmental, natural gas, oil and NGL related and occupational health and safety laws and regulations, including, but not limited to delays, curtailment or cessation of operations or exposure to material costs and liabilities;
•
difficult and adverse conditions in the domestic and global capital and credit markets and economies, including effects of diseases, political instability, including but not limited to instability related to the military conflict in Ukraine, and pricing and production decisions;
•
the concentration of our operations in the Appalachian Basin, the Barnett Shale, the Cotton Valley Formation, the Haynesville Shale of the United States and the Mid-Continent producing region;
•
potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity price risks;
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•
the failure by counterparties to our derivative risk management activities to perform their obligations;
•
shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;
•
access to pipelines, storage platforms, shipping vessels and other means of transporting and storing and refining gas and oil, including without limitation, changes in availability of, and access to, pipeline usage;
•
risks and liabilities associated with acquired properties, including, but not limited to, the assets acquired in connection with our recent acquisitions;
•
uncertainties about our ability to replace reserves;
•
our hedging strategy;
•
competition in the natural gas, oil and NGL industry; and
•
our substantial existing indebtedness. Reserve engineering is a process of estimating underground accumulations of natural gas, oil and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve and PV-10 estimates may differ significantly from the quantities of natural gas, oil and NGLs that are ultimately recovered.
You should refer to the section titled “Risk Factors” of this prospectus for a discussion of other important factors that may cause our actual results to differ materially from those expressed or implied by our forward-looking statements. As a result of these factors, we cannot assure you that the forward-looking statements in this prospectus will prove to be accurate.
In addition, statements that “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based upon information available to us as of the date of this prospectus, and although we believe such information forms a reasonable basis for such statements, such information may be limited or incomplete, and our statements should not be read to indicate that we have conducted a thorough inquiry into, or review of, all potentially available relevant information. These statements are inherently uncertain, and investors are cautioned not to unduly rely upon these statements. Furthermore, if our forward-looking statements prove to be inaccurate, the inaccuracy may be material. In light of the significant uncertainties in these forward-looking statements, you should not regard these statements as a representation or warranty by us or any other person that we will achieve our objectives and plans in any specified time frame, or at all. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
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USE OF PROCEEDS
We estimate that the net proceeds to us from this offering will be approximately $ million, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, based on an assumed initial public offering price of $ per ordinary share, the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE on , 2023 (based on an assumed exchange rate of £1.00 to $1. . If the underwriters exercise their option to purchase additional ordinary shares in full, we estimate that the net proceeds to be received by us will be approximately $ million, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.
Each $1.00 increase (decrease) in the assumed initial public offering price of $ per ordinary share would increase (decrease) the net proceeds to us from this offering by approximately $ million, assuming the number of ordinary shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and commissions and estimated offering expenses payable by us.
We may also increase or decrease the number of ordinary shares we are offering. Each increase (decrease) of 100,000 ordinary shares in the number of ordinary shares offered by us would increase (decrease) the net proceeds to us from this offering by approximately $ million, assuming that the assumed initial public offering price remains the same, and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us. We do not expect that a change in the initial public offering price or the number of ordinary shares by these amounts would have a material effect on our uses of the proceeds from this offering, although it may accelerate the timing of when we need to seek additional capital.
The principal purposes of this offering are to create a public market in the United States for our ordinary shares, facilitate access to the public equity markets and increase our visibility in the marketplace. We intend to use the net proceeds from this offering for working capital, to fund incremental growth and other general corporate purposes, including possible acquisitions that we view as accretive to our business.
The amount of what, and timing of when, we actually spend for these purposes may vary significantly and will depend on a number of factors, including our future revenue and cash generated by operations and the other factors described in the section titled “Risk Factors.” Accordingly, we will have broad discretion in deploying the net proceeds of this offering.
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DIVIDEND POLICY
We have consistently declared dividends on our ordinary shares since the admission of our shares to listing on the premium segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE. During the six months ended June 30, 2023 and 2022 and during the years ended December 31, 2022 and 2021, we declared and paid dividends of an aggregate of approximately $84 million, $72 million, $143 million and $130 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 the subsection titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility” for additional information on our Credit Facility.
While we cannot assure you that we will be able to pay cash dividends on our ordinary shares in future periods, we intend to, consistent with our historical performance since the LSE IPO (but subject to certain restrictions, including those above related to UK Law, and the terms of our Credit Facility), use a portion of our cash flow to pay regular dividends on our ordinary shares.
We have not adopted, and do not currently intend to adopt, a formal written Company dividend policy prior to the consummation of this offering.
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CAPITALIZATION
The following table sets forth our cash and cash equivalents and total capitalization as of December 31, 2022, as follows:
•
on an actual basis; and
•
on an as adjusted basis to reflect the issuance and sale of ordinary shares in this offering at the assumed initial public offering price of $ per ordinary share, the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2023 (based on an assumed exchange rate of £1.00 to $1. ), after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.
You should read this information in conjunction with our consolidated financial statements and the related notes appearing at the end of this prospectus and the sections titled “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other financial information contained in this prospectus.
| | |
As of December 31, 2022
|
| |||||||||
| | |
Actual
|
| |
As Adjusted(1)
|
| ||||||
| | |
(in thousands)
|
| |||||||||
Cash and cash equivalents
|
| | | $ | 7,329 | | | | |
$
|
|
| |
Total debt
|
| | | $ | l,498,166 | | | | | $ | | | |
Shareholders’ equity: | | | | | | | | | | | | | |
Ordinary shares, nominal value £0.01 per share: shares, actual; shares, as adjusted
|
| | | | | | | | | | | | |
Share capital
|
| | | | 11,503 | | | | | | | | |
Share premium account
|
| | | | 1,052,959 | | | | | | | | |
Treasury reserve
|
| | | | (100,828) | | | | | | | | |
Share based payment and other reserves
|
| | | | 17,650 | | | | | | | | |
Retained earnings (accumulated deficit)
|
| | | | (1,133,972) | | | | | | | | |
Non-controlling interest
|
| | | | 14,964 | | | | | | | | |
Total shareholders’ equity
|
| | | | (137,724) | | | | | | | | |
Total capitalization
|
| | | $ | 1,360,442 | | | | | $ | | | |
(1)
A $1.00 increase or decrease in the assumed initial public offering price of $ per ordinary share, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on, , 2023 (based on an assumed exchange rate of £1.00 to $1. ), would increase or decrease the as adjusted amount of each of cash and cash equivalents, share premium account, total equity and total capitalization by approximately $ million, assuming the number of ordinary shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us. An increase or decrease of 100,000 shares in the number of ordinary shares offered by us, as set forth on the cover page of this prospectus, would increase or decrease the as adjusted amount of each of cash and cash equivalents, share premium account, total equity and total capitalization by approximately $ million, assuming no change in the assumed initial public offering price of $ per ordinary share and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.
As adjusted equity amounts shown in the table above exclude the impact of:
•
ordinary shares issuable upon the exercise of options outstanding under our 2017 Equity Incentive Plan as of December 31, 2022 at a weighted-average exercise price of $ per share; and
•
ordinary shares reserved for future issuance under our 2017 Equity Incentive Plan as described in the subsection titled “Management—Equity Compensation Arrangements—2017 Equity Incentive Plan.”
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DILUTION
If you invest in our ordinary shares in this offering, your ownership interest will be diluted to the extent of the difference between the initial public offering price per ordinary share and the as adjusted net tangible book value per share immediately following the consummation of this offering.
At December 31, 2022, we had a historical net tangible book value of $ million, corresponding to a net tangible book value of $ per ordinary share. Net tangible book value per ordinary share represents the amount of our total assets less our total liabilities, excluding goodwill and other intangible assets, divided by the total number of our ordinary shares outstanding.
After giving effect to the sale by us of ordinary shares in this offering at the assumed initial public offering price of $ per ordinary share, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2023 (based on an assumed exchange rate of £1.00 to $1. ), after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, our as adjusted net tangible book value at December 31, 2022 would have been approximately $ million, representing $ per ordinary share. This represents an immediate increase in net tangible book value of $ per ordinary share to existing shareholders and an immediate dilution in net tangible book value of $ per ordinary share to new investors purchasing ordinary shares in this offering at the assumed initial public offering price. Dilution in net tangible book value per ordinary share to new investors is determined by subtracting as adjusted net tangible book value per ordinary share after this offering from the assumed initial public offering price per ordinary share paid by new investors.
The following table illustrates this dilution to new investors purchasing ordinary shares in the offering.
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Assumed initial public offering price per ordinary share
|
| | | | | | | | | $ | | | |
|
Historical net tangible book value per ordinary share as of December 31, 2022
|
| | | $ | | | | | | | | | |
|
Increase in net tangible book value per ordinary share attributable to this offering
|
| | | | | | | | | | | | |
|
As adjusted net tangible book value per ordinary share after this offering
|
| | | | | | | | | | | | |
|
Dilution per ordinary share to new investors in this offering
|
| | | | | | | | | $ | | | |
If the underwriters exercise their option to purchase additional ordinary shares from us in full, our as adjusted net tangible book value per ordinary share after this offering would be $ per ordinary share, representing an immediate increase in as adjusted net tangible book value of $ per ordinary share to existing shareholders and immediate dilution of $ per ordinary share in as adjusted net tangible book value to new investors purchasing ordinary shares in this offering, based on an assumed initial public offering price of $ per ordinary share, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2023 (based on an assumed exchange rate of £1.00 to $1. ).
Each $1.00 increase (decrease) in the assumed initial public offering price of $ per ordinary share, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2023 (based on an assumed exchange rate of £1.00 to $1. ), respectively, would increase (decrease) the as adjusted net tangible book value after this offering by $ per ordinary share and the dilution to new investors participating in the offering by $ per ordinary share, assuming that the number of ordinary shares offered by us, as set forth on the cover page of this prospectus, remains the same, and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of ordinary shares we are offering.
Similarly, an increase of 100,000 in the number of ordinary shares offered by us, as set forth on the cover page of this prospectus, would increase the as adjusted net tangible book value after this offering by $ per ordinary share and decrease the dilution to new investors participating in this offering by $ per ordinary share, assuming no change in the assumed initial public offering price per ordinary share and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. A decrease of 100,000 in the number of ordinary shares offered by us, as set forth on the cover page of this prospectus, would decrease the as adjusted net tangible book value after this offering by $ per ordinary share and increase the dilution to new investors participating in this offering by $ per
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ordinary share, assuming no change in the assumed initial public offering price per ordinary share and after deducting underwriting discounts and commissions and estimated offering expenses payable by us.
The following table summarizes, as of June 30, 2023, the total number of ordinary shares purchased from us, the total consideration paid to us and the average price per share paid by the existing shareholders and by new investors purchasing ordinary shares in this offering.
| | |
Ordinary Shares
Purchased |
| |
Total Consideration
|
| |
Average
Price Per Share |
| |||||||||||||||||||||
| | |
Number
|
| |
Percent
|
| |
Amount
|
| |
Percent
|
| ||||||||||||||||||
Existing shareholders
|
| | | | | | | | | | % | | | | | $ | | | | | | % | | | | | $ | | | ||
New investors
|
| | | | | | | | | | | | | | | | | | | | | | | | $ | | | ||||
Total
|
| | | | | | | | | | 100.0% | | | | | $ | | | | | | 100.0% | | | | | | | | |
To the extent any of our outstanding options is exercised, there will be further dilution to new investors.
If the underwriters exercise their option to purchase additional ordinary shares in full:
•
the percentage of ordinary shares held by existing shareholders will decrease to approximately % of the total number of our ordinary shares outstanding after this offering; and
•
the percentage of ordinary shares held by new investors will increase to approximately % of the total number of our ordinary shares outstanding after this offering.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion together with the consolidated financial statements and related notes included elsewhere in this prospectus. The statements in this discussion regarding industry outlook, our expectations regarding our future performance, liquidity and capital resources and other non-historical statements in this discussion are forward-looking statements. These forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described in the sections titled “Risk Factors” and “Special Note Regarding Forward-Looking Statements.” Our actual results may differ materially from those contained in or implied by any forward-looking statements. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Overview
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.
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 $1.3 billion during the six months ended June 30, 2023 and the years ended December 31, 2022 and 2021, comprised of:
•
March 2023: The Tanos II Assets Acquisition, in which we acquired certain upstream assets and related infrastructure in the Central Region;
•
September 2022: The ConocoPhillips Assets Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region
•
July 2022: Certain plugging infrastructure in the Appalachian Region;
•
May 2022: Certain plugging infrastructure in the Appalachian Region;
•
April 2022:
•
The East Texas Assets Acquisition, in which we acquired working interests in certain upstream assets and related facilities within the Central Region from a private seller, in conjunction with Oaktree;
•
Certain midstream assets, inclusive of a processing facility, in the Central Region that was contiguous to our East Texas assets;
•
February 2022: Certain plugging infrastructure in the Appalachian Region;
•
December 2021: The Tapstone Acquisition, where we acquired working interests in certain upstream assets, field infrastructure, equipment and facilities within the Central Region in conjunction with Oaktree;
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•
August 2021: The Tanos Acquisition, in which we acquired working interests in certain upstream assets, field infrastructure, equipment and facilities in the Central Region in conjunction with Oaktree;
•
July 2021: The Blackbeard Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region; and
•
May 2021: The Indigo Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region.
Our strategic acquisitions may affect the comparability of our financial results with prior and subsequent periods. We intend to continue to selectively pursue strategic acquisitions to further strengthen our competitiveness. We will evaluate and execute opportunities that complement and scale our business, optimize our profitability, help us expand into adjacent markets and add new capabilities to our business. The integration of acquisitions also requires dedication of substantial time and resources of management, and we may never fully realize synergies and other benefits that we expect.
Commodity Price Volatility
Changes in commodity prices may affect the value of our natural gas and oil reserves, operating cash flow and Adjusted EBITDA, regardless of our operating performance. It is impossible to accurately predict future natural gas, NGLs and oil price movements. Historically, natural gas prices have been highly volatile and subject to large fluctuations in response to relatively minor changes in the demand for natural gas.
We employ a hedging strategy in which we opportunistically hedge a majority of our first two years of production and a significant percentage of production beyond our first two years of forecasted production. Even so, the remainder of our production that is unhedged is exposed to commodity price volatility. As a result our results of operations and financial condition would be negatively impacted if the prices of natural gas, NGLs or oil were to remain depressed or decline materially from current levels. To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of natural gas, NGLs and oil we may enter into additional hedging arrangements for a significant portion of our production. The terms of our Credit Facility and ABS Notes (as defined herein) also require us to hedge our production.
Our price hedging strategy and future hedging transactions will be determined at our discretion, subject to the terms of certain agreements governing our indebtedness. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize higher cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our natural gas, NGLs and oil revenues becoming more sensitive to commodity price fluctuations.
Although the current outlook on natural gas, NGLs and oil prices is generally favorable, and our operations have not been significantly impacted by material declines in commodity prices in the short-term, in the event future disruptions to pricing occur and continue for an extended period of time, the unhedged portion of our cash flows could be adversely impacted.
Recent Developments
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.
Continued inflationary pressures could impact our profitability. Though we believe that the rates of inflation in recent years, including in the twelve 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. With respect to our costs of capital, our ABS Notes are fixed-rate instruments (subject to rate increases pursuant
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to the sustainability-linked features described under the subsection titled “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt”), and as of June 30, 2023, we had approximately $265 million outstanding on our Credit Facility which is subject to variable interest rates. Inflation may also affect our ability to enter into future debt financing, including refinancing of our Credit Facility or issuing additional SPV-level asset backed securities, as high inflation may result in a relative increase in the cost of debt capital.
Segment Reporting
We are an independent owner and operator of producing natural gas and oil wells with properties located in the states of Tennessee, Kentucky, Virginia, West Virginia, Ohio, Pennsylvania, Oklahoma, Texas and Louisiana. Our strategy is to acquire long-life producing assets, efficiently operate those assets to 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 prospectus 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 subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures” for a reconciliation of the Non-IFRS measures included in the table to the most directly comparable IFRS financial performance measure.
| | |
Six Months Ended
|
| |||||||||||||||||||||
| | |
June 30, 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) | | | | | | (1 |