AMPLIFY ENERGY CORP._December 31, 2024
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
For the fiscal year ended December 31, 2024
OR
For the transition period from to .
Commission File Number: 001-35512
AMPLIFY ENERGY CORP.
(Exact name of registrant as specified in its charter)
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (832) 219-9001
Securities Registered Pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Stock AMPY NYSE
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐No☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐No☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yesþ No ◻
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b–2 of the Exchange Act.
Large accelerated filer ☐ Accelerated filer ☑
Non-accelerated filer ☐ Smaller reporting company ☑
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ☐ No ☑
The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $202.1 million on June 30, 2024, based on $6.78 per share, the last reported sales price of the shares on the New York Stock Exchange on such date.
As of February 28, 2025, the registrant had 40,332,937 outstanding shares of common stock, $0.01 par value per share.
Documents Incorporated By Reference: Portions of the registrant’s definitive proxy statement relating to its 2024 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2024, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Form 10-K.
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AMPLIFY ENERGY CORP.
TABLE OF CONTENTS
Page
PART I
Item 1. Business 13
Item 1A. Risk Factors 38
Item 1B. Unresolved Staff Comments 63
Item 1C. Cybersecurity 63
Item 2. Properties 64
Item 3. Legal Proceedings 64
Item 4. Mine Safety Disclosures 64
PART II
Item 6. Reserved 65
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 82
Item 8. Financial Statements and Supplementary Data 83
Item 9A. Controls and Procedures 83
Item 9B. Other Information 85
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection 85
PART III
Item 10. Directors, Executive Officers and Corporate Governance 86
Item 11. Executive Compensation 86
Item 14. Principal Accountant Fees and Services 86
PART IV
Item 15. Exhibits, Financial Statement Schedules 87
Signatures 90
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GLOSSARY OF OIL AND NATURAL GAS TERMS
3-D seismic: Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.
API Gravity: The American Petroleum Institute’s system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.
Basin: A large depression on the earth’s surface in which sediments accumulate.
Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
Boe/d: One Boe per day.
BOEM: Bureau of Ocean Energy Management.
BSEE: Bureau of Safety and Environmental Enforcement.
Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one-degree Fahrenheit.
CO2: Carbon dioxide.
Deterministic Estimate: The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.
Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. Examples include the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
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 and taxes.
Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue is determined at the terminal point of oil and natural gas producing activities.
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Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves) but which generally has a lower risk than that associated with exploration projects.
Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
GAAP: Generally accepted accounting principles in the United States of America.
Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have a working interest.
ICE: Inter-Continental Exchange.
MBbl: One thousand Bbls.
MMBbls: One million stock tank barrels.
MBoe: One thousand barrels of oil equivalent.
MBoe/d: One thousand barrels of oil equivalent per day.
MMBoe: One million barrels of oil equivalent.
Mcf: One thousand cubic feet of natural gas.
MMBtu: One million British thermal units.
MMcf: One million cubic feet of natural gas.
MMcfe: One million cubic feet of natural gas equivalent.
Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.
Net Production: Production that is owned by us less royalties and production due others.
Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.
NGLs: The combination of ethane, propane, butane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
NYSE: New York Stock Exchange.
Oil: Oil and condensate.
Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Plugging and abandonment: Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface. Regulations of all states require plugging of abandoned wells.
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Present value of future net revenues or PV-9: The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 9% in accordance with the guidelines of the SEC.
Present value of future net revenues or PV-10: The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.
Probabilistic Estimate: The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.
Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.
Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs 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 reasonably 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. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil 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 geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves that can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-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 (“PUDs”): Proved oil and natural gas 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 are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved 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 tests in the area and in the same reservoir.
Realized Price: The cash market price less all expected quality, transportation and demand adjustments.
Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
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Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to reflect property acquisitions and dispositions.
Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.
SEC: The U.S. Securities and Exchange Commission.
Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less estimated future development, production and income tax expenses and discounted at 10% per annum to reflect the timing of future net revenue. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in our oil and natural gas properties. 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 oil and natural gas regardless of whether such acreage contains proved reserves.
Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.
Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and generally requires the owner to pay a share of the costs of drilling and production operations.
Workover: Operations on a producing well to restore or increase production.
WTI: West Texas Intermediate.
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NAMES OF ENTITIES
As used in this 2024 Annual Report on Form 10-K (this “Annual Report”), unless we indicate otherwise:
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FORWARD–LOOKING STATEMENTS
This Annual Report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:
● business strategies;
● acquisition and disposition strategy;
● cash flows and liquidity;
● financial strategy;
● ability to replace the reserves we produce through drilling;
● drilling locations;
● oil and natural gas reserves;
● technology;
● realized oil, natural gas and NGL prices;
● production volumes;
● lease operating expense;
● gathering, processing and transportation;
● general and administrative expense;
● future operating results;
● ability to procure drilling and production equipment;
● ability to procure oil field labor;
● ability to access capital markets;
● marketing of oil, natural gas and NGLs;
● expectations regarding general economic conditions, including inflation;
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● competition in the oil and natural gas industry;
● effectiveness of risk management activities;
● environmental liabilities;
● counterparty credit risk;
● expectations regarding governmental regulation and taxation;
● plans, objectives, expectations and intentions.
All statements, other than statements of historical fact, included in this report are forward-looking statements. These forward-looking statements may be found in “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references. These forward-looking statements involve risks and uncertainties. Important factors that could cause the Company’s actual results or financial condition to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the following risks and uncertainties:
● the Company’s ability to satisfy its debt obligations;
● volatility in the prices for oil, natural gas and NGLs;
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● potential difficulties in the marketing of oil and natural gas;
● changes to the financial condition of counterparties;
● competition in the oil and natural gas industry;
● other risks and uncertainties described in “Item 1A. Risk Factors.”
The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by the Company’s management. These estimates and assumptions reflect the Company’s best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond the Company’s control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Item 1A. Risk Factors” and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on the Company’s behalf.
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RISK FACTOR SUMMARY
Our business is subject to numerous risks and uncertainties, including those highlighted in this section titled “Risk Factors” and summarized below. We have various types of risks, including risks related to our business and industry; information technology, data security and privacy; legal, regulatory, accounting, and tax matters; our common stock; and our Revolving Credit Facility, which are discussed more fully elsewhere in this Annual Report. As a result, this risk factor summary does not contain all of the information that may be important to you, and you should read this risk factor summary together with the more detailed discussion of risks and uncertainties set forth following this section under the heading “Risk Factors,” as well as elsewhere in this Annual Report. These risks include, but are not limited to, the following:
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PART I
ITEM 1.BUSINESS
References
Amplify Energy Corp. (“Amplify Energy,” the “Company,” “we,” “us,” “our,” or similar terms), is a publicly traded Delaware corporation, in which our common stock, par value of $0.01 per share (“Common Stock”), is listed on the NYSE under the symbol “AMPY.”
Overview
Amplify Energy is an independent oil and natural gas company engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment, as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties located in Oklahoma, the Rockies (“Bairoil”), federal waters offshore Southern California (“Beta”), East Texas/North Louisiana, and Eagle Ford (Non-op). Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs.
The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. As of December 31, 2024:
Recent Developments
East Texas Haynesville Monetization
In December 2024, we sold certain rights, title and interest in assets located in East Texas to a third party. We recorded a gain of approximately $1.4 million.
In January 2025, we purchased and sold certain rights, title and interest in assets in East Texas from a third party, whereby we received net proceeds of $6.2 million.
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Merger with Juniper Capital
On January 14, 2025, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Amplify DJ Operating LLC, a Delaware limited liability company and indirect wholly owned subsidiary of the Company (“First Merger Sub”), Amplify PRB Operating LLC, a Delaware limited liability company and indirect wholly owned subsidiary of Amplify (“Second Merger Sub,” and together with First Merger Sub, the “Merger Subs”), North Peak Oil & Gas, LLC, a Delaware limited liability company (“NPOG”), Century Oil and Gas Sub-Holdings, LLC, a Delaware limited liability company (“COG” and, together with NPOG, each, an “Acquired Company” and, collectively, the “Acquired Companies”), and, solely for the limited purposes set forth in the Merger Agreement (as defined below), Juniper Capital Advisors, L.P., a Delaware limited partnership (“Juniper”), and the Specified Company Entities set forth on Annex A thereto, pursuant to which, at the effective time of the Mergers (as defined below) (the “Effective Time”), (a) NPOG will merge with and into First Merger Sub, with NPOG surviving the merger as an indirect, wholly owned subsidiary of the Company and (b) COG will merge with and into Second Merger Sub, with COG surviving the merger as an indirect, wholly owned subsidiary of the Company, in each case, subject to the terms and conditions of the Merger Agreement.
Subject to the terms and conditions of the Merger Agreement, at the Effective Time, all of the issued and outstanding limited liability company interests of each of the Acquired Companies will automatically be converted into the right to receive, in the aggregate, 26,729,315 validly issued, fully paid and nonassessable shares (the “Aggregate Merger Consideration”) of Common Stock. Following the Effective Time, the Company's existing stockholders and the Acquired Companies' existing equityholders are expected to own approximately 61% and 39%, respectively, of the combined company's outstanding equity.
Mr. Christopher W. Hamm will serve as Chairman of our board of directors (the “Board”), and Mr. Martyn Willsher will continue to serve as the Chief Executive Officer of the Company after the Effective Time. The Merger Agreement provides that the Board will consist of the following seven members: Martyn Willsher, Christopher W. Hamm, Deborah G. Adams, James E. Craddock, Vidisha Prasad, Edward Geiser and Josh Schmidt. Further, Josh Schmidt will be appointed as Chairman of the compensation committee of the Board (the “Compensation Committee”), and Edward Geiser will be appointed as a member of the nominating and governance committee of the Board (the “Nominating & Governance Committee”).
The Merger Agreement contains customary representations, warranties and covenants of the Company and the Acquired Companies, including covenants relating to the conduct of the business of both the Company and the Acquired Companies from the date of signing the Merger Agreement through closing of the Mergers (the “Closing”), obtaining the requisite approval of the stockholders of the Company and maintaining the listing of the Common Stock on the NYSE. Under the terms of the Merger Agreement, the Company has also agreed not to solicit from any person an acquisition proposal for the Company.
In connection with the Mergers, the Company will seek the approval of the Company’s stockholders with respect to the issuance of the Aggregate Merger Consideration in connection with the Closing (the “Stock Issuance Proposal”).
The Mergers are expected to close in the second quarter of 2025.
No Offer or Solicitation. This section of the Annual Report relates to a proposed business combination transaction between the Company and the Acquired Companies. This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the business combination transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.
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Important Additional Information Regarding the Mergers Will Be Filed With the SEC. In connection with the proposed Mergers, the Company has filed a definitive proxy statement. The definitive proxy statement will be sent to the stockholders of the Company. The Company may also file other documents with the SEC regarding the Mergers. INVESTORS AND SECURITY HOLDERS OF AMPLIFY ENERGY ARE ADVISED TO CAREFULLY READ THE DEFINITIVE PROXY STATEMENT AND ANY OTHER RELEVANT MATERIALS FILED WITH THE SEC WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE MERGERS, THE PARTIES TO THE MERGERS AND THE RISKS ASSOCIATED WITH THE MERGERS. Investors and security holders may obtain a free copy of the definitive proxy statement and other relevant documents filed by Amplify Energy with the SEC from the SEC’s website at www.sec.gov. Security holders and other interested parties will also be able to obtain, without charge, a copy of the definitive proxy statement and other relevant documents (when available) by (1) directing your written request to: 500 Dallas Street, Suite 1700, Houston, Texas or (2) contacting our Investor Relations department by telephone at (832) 219-9044 or (832) 219-9051. Copies of the documents filed by the Company with the SEC will be available free of charge on the Company’s website at http://www.amplifyenergy.com.
Participants in the Solicitation. Amplify Energy and certain of its respective directors, executive officers and employees may be considered participants in the solicitation of proxies in connection with the proposed transaction. Information regarding the persons who may, under the rules of the SEC, be deemed participants in the solicitation of the stockholders of Amplify Energy in connection with the transaction, including a description of their respective direct or indirect interests, by security holdings or otherwise, is included in the definitive proxy statement filed with the SEC. Additional information regarding the Company’s directors and executive officers is also included in Amplify’s Notice of Annual Meeting of Stockholders and 2024 Proxy Statement, which was filed with the SEC on April 5, 2024. These documents are available free of charge as described above.
Industry Trends
We continue to monitor the impact of the actions of the Organization of the Petroleum Exporting Countries and other large producing nations; the Russia-Ukraine conflict; conflicts in the Middle East; global inventories of oil and natural gas and the uncertainty associated with recovering oil demand; inflation and future monetary policy; and governmental policies aimed at transitioning towards lower carbon energy. The Russia-Ukraine conflict and conflicts in the Middle East continue to evolve, and the extent to which these events may impact our business, results of operations, financial condition and cash flows will depend on future developments, which are highly uncertain and cannot be predicted with confidence.
Properties
We engaged Cawley, Gillespie and Associates, Inc. (“CG&A”), our independent reserve engineers, to prepare our reserves estimates for all of our proved reserves at December 31, 2024. The following table summarizes information, based on a reserve report prepared by CG&A (which we refer to as our “reserve report”), about our proved oil and natural gas reserves by geographic region as of December 31, 2024, and our average net production for the three months ended December 31, 2024:
Average Net
Estimated Net Proved Reserves Production Average
% Oil Reserve-to
(Years)
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Our Areas of Operation
Oklahoma
Approximately 29% of our estimated proved reserves as of December 31, 2024 and approximately 26% of our average daily net production for the three months ended December 31, 2024 were located in the Oklahoma region. Our Oklahoma properties include wells and properties primarily located in Alfalfa and Woods counties in Oklahoma. Those properties collectively contained 27.0 MMBbls of estimated net proved reserves as of December 31, 2024 based on our reserve report and generated average net production of 4.7 MBoe/d for the three months ended December 31, 2024.
Bairoil
Approximately 18% of our estimated proved reserves as of December 31, 2024 and approximately 17% of our average daily net production for the three months ended December 31, 2024 were located in Bairoil. Our Bairoil properties include wells and properties primarily located in the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Bairoil properties contained 16.4 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2024 based on our reserve report and generated average net production of 3.2 MBoe/d for the three months ended December 31, 2024.
Beta
Approximately 20% of our estimated proved reserves as of December 31, 2024 and approximately 18% of our average daily net production for the three months ended December 31, 2024 were associated with the Beta field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. Our ownership in Beta consists of 100% of the working interests and 75.2% average net revenue interest in three Pacific Outer Continental Shelf lease blocks (P-0300, P-0301 and P-0306) (referred to as the “Beta Unit”) in the Beta field. The Beta properties contained 19.1 MMBbls of estimated net proved oil reserves as of December 31, 2024 based on our reserve report and generated average net production of 3.3 MBoe/d for the three months ended December 31, 2024. Oil and gas are produced from the Beta Unit via two production platforms, referred to as the Ellen and Eureka platforms, equipped with permanent drilling rigs and associated equipment. On a third platform, Elly, the oil, water and gas are separated, and the oil is prepared for sale, while the gas is utilized as fuel for power and the water is recycled back into the reservoir for pressure maintenance. Sales quality oil is then pumped from the Elly platform to the Beta pump station located onshore at the Port of Long Beach, California via a 16-inch diameter oil pipeline, which extends approximately 17.5 miles. Amplify Energy’s wholly owned subsidiary, San Pedro Bay Pipeline Company owns and operates the pipeline system.
Based on our reserve report, the Beta field contains more than 15% of our total estimated reserves as of December 31, 2024. The following table summarizes production volumes from this field for the period presented:
December 31,
Production Volumes (1):
NGLs (MBbls) — —
Natural Gas (MMcfe) — —
Average net production (MBoe/d) 3.2 1.9
(1)The Beta field restarted production in April 2023.
East Texas / North Louisiana
Approximately 30% of our estimated proved reserves as of December 31, 2024 and approximately 36% of our average daily net production for the three months ended December 31, 2024 were located in the East Texas/ North Louisiana region. Our East Texas/ North Louisiana properties include wells and properties primarily located in the Joaquin, Carthage, Willow Springs and East Henderson fields in East Texas. Those properties collectively contained 28.0 MMBoe of estimated net proved reserves as of December 31, 2024 based on our reserve report and generated average net production of 6.6 MBoe/d for the three months ended December 31, 2024.
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Eagle Ford
Approximately 3% of our estimated proved reserves as of December 31, 2024 and approximately 4% of our average daily net production for the three months ended December 31, 2024 were located in the Eagle Ford region. Our Eagle Ford properties include wells and properties in fields located primarily in the Eagleville fields. Our Eagle Ford properties contained 2.5 MMBoe of estimated net proved reserves as of December 31, 2024 based on our reserve report. Those properties collectively generated average net production of 0.7 MBoe/d for the three months ended December 31, 2024.
Our Oil and Natural Gas Data
Our Reserves
Internal Controls. Our proved reserves were estimated at the well or unit level for reporting purposes by CG&A, our independent reserve engineers. We maintain internal evaluations of our reserves in a secure reserve engineering database. CG&A interacts with our internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting, and marketing employees to obtain the necessary data to prepare our proved reserves report. Reserves are reviewed and approved internally by our senior management on an annual basis and evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our Revolving Credit Facility. Our reserve estimates are prepared by CG&A at least annually.
Our internal professional staff works closely with CG&A to ensure the integrity, accuracy and timeliness of data that is furnished to them in order to prepare the reserves report. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide CG&A with other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their preparation of our reserves.
Qualifications of Responsible Technical Persons
Internal Engineers. Tony Lopez is the technical person at the Company, primarily responsible for overseeing and providing oversight of the preparation of the reserves estimates with our third-party reserve engineers.
Mr. Lopez has over 17 years of corporate reserve reporting experience. Mr. Lopez joined the Company as Vice President of Corporate Reserves in June 2018 and currently serves as the Company’s Senior Vice President of Engineering & Exploitation. Prior to that Mr. Lopez was Vice President of Acquisitions and Engineering for EnerVest, Ltd., where he managed the corporate reserve reporting process and the financial planning & analysis department. Mr. Lopez is a graduate of West Virginia University and holds a B.S. in Petroleum and Natural Gas Engineering. Mr. Lopez is an active member of the Society of Petroleum Engineers.
Cawley, Gillespie and Associates Inc. CG&A is an independent oil and natural gas consulting firm. No director, officer, or key employee of CG&A has any financial ownership in us or any of our affiliates. CG&A’s compensation for the preparation of its report is not contingent upon the results obtained and reported. CG&A has not performed other work for us or any of our affiliates that would affect its objectivity. The estimates of our proved reserves presented in the CG&A reserve report were overseen by Todd Brooker.
Mr. Brooker became the President of CG&A in 2017 and has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron Corporation. Mr. Brooker’s experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.
Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
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Estimated Proved Reserves
The following table summarizes our estimated proved oil and natural gas reserves and related standardized measure of discounted future net cash flows attributable to our properties as of December 31, 2024, which are based on the prepared reserve report by CG&A, our independent reserve engineers.
Reserves
Oil Natural Gas NGLs Total
(MBbls) (MMcf) (MBbls) (MBoe) (1)
Estimated Proved Reserves
Proved developed reserves as a percentage of total proved reserves 88 %
Standardized measure (in thousands) (2) $ 608,239
PV-10 (in thousands) (3) $ 735,765
Oil and Natural Gas Prices (4)
Oil – WTI ($ per Bbl) $ 75.48
Natural gas – Henry Hub ($ per MMBtu) $ 2.13
The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered.
Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate standardized measure, which is required by the SEC and FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For these reasons, neither standardized measure nor PV-10 should be construed as the fair value of our oil and natural gas reserves.
For a discussion of risks associated with internal reserve estimates, see “Item 1A. Risk Factors — Risks Related to Our Business — Our estimated reserves and future production rates are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”
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Development of Proved Undeveloped Reserves
As of December 31, 2024, we had 10,756 MBoe of PUDs, comprised of 9,083 MBbls of oil, 8,915 MMcf of natural gas and 187 MBbls of NGLs. None of our PUDs as of December 31, 2024 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
For the year ended December 31, 2024, total PUDs increased by 8,830 MBoe. The increase includes 9,390 MBoe due to the addition of 23 Beta PUD locations, 4 non-operated PUDs in East Texas drilled and waiting on completion, and 4 non-operated Eagle Ford PUDs drilled and waiting on completion. We also had transfers of (524) MBoe to proved developed reserves as a result of the 2024 Beta drilling program. We removed 7 Eagle Ford PUDs (162) MBoe, due to the extension of the development plan beyond five years. Other revisions consisted of 126 MBoe that were primarily related to Beta PUD performance.
Approximately 27.2% (524 MBoe) of our PUDs recorded as of December 31, 2024 were developed during the twelve months ended December 31, 2024. Total costs incurred in 2024 to develop these PUDs were approximately $10.9 million. In total, we incurred total capital expenditures of approximately $30.7 million during fiscal year 2024 developing PUDs, which includes $19.8 million associated with PUDs to be completed in 2025. Based on our current expectations of our cash flows, we believe that we can fund the drilling of our current PUD inventory and our expansions in the next five years from our cash flow from operations and borrowings under our Revolving Credit Facility. For a more detailed discussion of our liquidity position, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
Production, Revenue and Price History
For a description of our production, revenues, and average sales prices and per unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”
The following tables summarize our average net production, average unhedged sales prices by product and average lease operating cost expense per Boe by geographic region for the years ended December 31, 2024 and 2023, respectively:
For the Year Ended December 31, 2024
Oil NGLs Natural Gas Total
Average Average Average Average Lease
Average net production (MBoe/d) 19.5
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For the Year Ended December 31, 2023
Oil NGLs Natural Gas Total
Average Average Average Average Lease
(MBbls) ($/Bbl) (MBbls) ($/Bbl) (MMcf) ($/Mcf) (MBoe) ($/Boe) ($/Boe)
Average net production (MBoe/d) 20.5
(1) The Beta field restarted production in April 2023.
Productive Wells
Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2024.
Oil Natural Gas
Gross Net Gross Net
Developed Acreage
Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2024, substantially all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2024 relating to our leasehold acreage.
Region Developed Acreage (1)
Gross (2) Net (3)
Undeveloped Acreage
As of December 31, 2024, we had no gross and net undeveloped acreage expiring over the next two years as all of our gross and net acreage is currently held by production.
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Drilling Activities
Our drilling activities primarily consist of development wells. The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. At December 31, 2024, we had 24 gross (3.8 net) wells that were in various stages of completion.
For the Year Ended December 31,
Gross Net Gross Net
Development wells:
Dry — — — —
Exploratory wells:
Productive — — — —
Dry — — — —
Total wells:
Dry — — — —
Delivery Commitments
We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near future under our existing sales contracts.
Operations
General
As of December 31, 2024, the Company is the operator of record of properties containing 92% of our total estimated proved reserves. We design and manage the development, recompletion and/or workover operations, and supervise other operation and maintenance activities for all of the wells we operate. We do not own the drilling rigs used for drilling wells on our onshore properties; independent contractors provide all the equipment and personnel associated with these activities. Our Beta platforms have permanent drilling systems in place.
Marketing and Major Customers
The following individual customers each accounted for 10% or more of our total reported revenues for the period indicated:
For the Year Ended
December 31,
Major customers:
HF Sinclair Corporation (formerly: Sinclair Oil & Gas Company) 25 % 24 %
Southwest Energy LP 10 % 13 %
The production sales agreements covering our properties contain customary terms and conditions for the oil and natural gas industry and provide for sales based on prevailing market prices. A majority of those agreements have terms that renew on a month-to-month basis until either party gives advance written notice of termination.
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If we were to lose any one of our customers, the loss could temporarily delay production and sale of a portion of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether and we were unable to replace them, the loss of any such customer could have a detrimental effect on our production volumes and revenues in general.
In October 2024, Phillips 66 announced its plan to cease operations at its Los Angeles area refinery in the fourth quarter of 2025. This refinery has historically represented a significant portion of our sales to Phillips 66. We are actively engaging in discussions with Phillips 66 to understand the full scope of the impact on our business. While the closure of this refinery has the potential to materially affect our future sales to this customer, we anticipate that a commercial agreement will be reached with another customer to purchase our California crude oil. The inability to obtain such agreement or to obtain an agreement with less favorable terms than the current agreement with Phillips 66 could negatively impact our revenue, earnings and cash from operating activities.
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with industry standards. More thorough title investigations are customarily made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under natural gas leases, or net profits interests.
Derivative Activities
We enter into commodity derivative contracts with unaffiliated third parties, generally lenders under our Revolving Credit Facility or their affiliates, to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 50% − 75% of our estimated production from total proved developed producing reserves over a one-to-three-year period at any given point of time. We may, however, from time to time, hedge more or less than this approximate amount.
Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those in our Revolving Credit Facility) to fixed interest rates.
It is our policy to enter into derivative contracts only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our Revolving Credit Facility are counterparties to our derivative contracts. We will continue to evaluate the benefit of employing derivatives in the future.
Competition
We operate in a highly competitive environment for acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us.
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Seasonal Nature of Business
The price we receive for our natural gas production is impacted by seasonal fluctuations in demand for natural gas. The demand for natural gas typically peaks during the coldest months and tapers off during the milder months, with a slight increase during the summer to meet the demands of electric generators. The weather during any particular season can affect this cyclical demand for natural gas. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.
Hydraulic Fracturing
Hydraulic fracturing is used as a means to maximize the productivity of almost every well that we drill and complete, except in our offshore wells. Hydraulic fracturing is a necessary part of the completion process because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. Our proved developed non-producing and proved undeveloped reserves make up 19.4% of the total proved reserves, with approximately 30.7% of these requiring hydraulic fracturing as of December 31, 2024.
We believe we have followed and continue to substantially follow applicable industry standard practices and legal and regulatory requirements for groundwater protection in our hydraulic fracturing operations, which are subject to supervision by state and federal regulators (including the U.S. Bureau of Land Management (the “BLM”) on federal acreage). These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design is intended to essentially eliminate a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.
Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abnormal change occurred to the injection pressure or annular pressure.
Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand, and the fluids are managed and used in accordance with applicable requirements.
Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it into approved disposal or injection wells. We currently do not discharge water to the surface.
For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, see “— Environmental, Occupational Health and Safety Matters and Regulations — Hydraulic Fracturing.”
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Insurance
In accordance with customary industry practice, we maintain insurance against many, but not all, potential losses or liabilities arising from our operations and at costs that we believe to be economic. We regularly review our risks of loss and the cost and availability of insurance and revise our insurance accordingly. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses. We currently have insurance policies that include the following:
· Commercial General Liability; · Oil Pollution Act Liability;
· Primary Umbrella / Excess Liability; · Pollution Legal Liability;
· Property; · Charterer’s Legal Liability;
· Workers’ Compensation; · Non-Owned Aircraft Liability;
· Employer’s Liability; · Automobile Liability;
· Maritime Employer’s Liability; · Directors & Officers Liability;
· U.S. Longshore and Harbor Workers’; · Employment Practices Liability;
· Energy Package/Control of Well; · Crime; and
· Loss of Production Income; · Fiduciary Liability.
· Cybersecurity;
We continuously monitor regulatory changes and comments and consider their impact on the insurance market, along with and our overall risk profile. As necessary, we will adjust our risk and insurance program to provide protection at a level we consider appropriate while weighing the cost of insurance against the potential and magnitude of disruption to our operations and cash flows. Changes in laws and regulations could lead to changes in underwriting standards, limitations on scope and amount of coverage, and higher premiums, including possible increases in liability caps for claims of damages from oil spills.
Environmental, Occupational Health and Safety Matters and Regulations
General
Our oil and natural gas development and production operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, occupational health and safety aspects of our operations, or otherwise relating to protection of the environment and natural resources. These laws and regulations impose numerous obligations applicable to our operations, including the acquisition of certain permits before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; the suspension or revocation of necessary permits, licenses and authorizations; the requirement that additional pollution controls be installed; and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. We may also experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. In addition, the long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
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Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from our own actions that were in compliance with all applicable laws at the time such actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. New laws and regulations continue to be enacted, particularly at the state level, and the long-term trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent new or more stringent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
The following is a summary of the more significant existing environmental, occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our operations, capital expenditures, earnings or competitive position.
Offshore Operations
Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters, and those operations are regulated by agencies such as BOEM and BSEE, which have broad authority to regulate our oil and gas operations associated with our Beta properties.
BOEM is responsible for managing environmentally and economically responsible development of the nation’s offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, and National Environmental Policy Act (“NEPA”) analysis and environmental review. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. BOEM generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. In October 2020, BOEM and BSEE issued a proposed rule to clarify, streamline, and provide greater transparency to financial assurance requirements for the oil and gas industry, including streamlining the evaluation criteria for determining if and when additional security is required for Outer Continental Shelf (“OCS”) leases, pipeline rights-of-way and rights-of-use and easement (“RUE”) and revising the process for issuing decommissioning obligations for facilities on the OCS. Pursuant to prior Executive Order 13990, BOEM decided not to move forward with the BOEM-administered portions, and instead issued a new notice of proposed rulemaking to address the financial policy concerns. BSEE finalized the BSEE-related provisions, which became effective on May 18, 2023, to focus on clarifying decommissioning obligations of RUE grant holders and promulgate BSEE policy regarding the obligations of predecessors that must decommission their units. In April 2024, BOEM announced a final rule, which modified criteria for determining whether oil, gas, and sulfur lessees, RUE grant holders, and pipeline right-of-way grant holders are required to provide bonds or other financial assurance above what is currently required to ensure compliance with OCS obligations. The final rule also codified the use of the BSEE’s probabilistic estimates of decommissioning costs in setting the levels of demand for supplemental financial assurance, removed restrictive provisions for third-party guarantees and decommissioning accounts, and added new criteria for cancelling supplemental financial assurance.
BSEE is responsible for safety and environmental oversight of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and training and environmental compliance programs. BSEE regulations require offshore production facilities and pipelines located on the OCS to meet stringent engineering and construction specifications, and in August 2023 and August 2024 BSEE announced two final rules which added safety-related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes and manage equipment used in high pressure high temperature environments. BSEE regulations also restrict the flaring or venting of natural gas, prohibit the flaring of liquid hydrocarbons and govern the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities.
BOEM and BSEE have adopted regulations providing for enforcement actions, including civil penalties and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta properties be suspended or terminated, and we may be subject to civil or criminal liability, which may have a negative impact on our operations, capital expenditures, earnings or competitive position.
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In addition to permits and approvals required by BOEM and BSEE, approvals and permits may be required from other agencies for the oil and gas operations associated with our Beta properties, such as the U.S. Coast Guard, the EPA, U.S. Department of Transportation, U. S. Army Corps of Engineers and the South Coast Air Quality Management District.
Hazardous Substances and Waste Handling
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also referred to as the Superfund law and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed “responsible parties.” These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Also, comparable state statutes may not contain a similar exemption for petroleum, and it is also not uncommon for neighboring landowners and other third parties to file common law-based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.
The Oil Pollution Act of 1990 (“OPA”) is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of, and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a cleanup. We are also subject to analogous state statutes that impose liabilities with respect to oil spills. For example, the California Department of Fish and Wildlife’s Office of Oil Spill Prevention and Response has adopted oil-spill prevention regulations that overlap with federal regulations.
We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible that these wastes, which could include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Any such changes, including to state programs, could result in an increase in our costs to manage and dispose of oil and gas waste, which could have a material adverse effect on our maintenance capital expenditures and operating expenses.
It is possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials (“NORM”). NORM are present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes into contact with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.
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Administrative, civil and criminal penalties can be imposed for failure to comply with hazardous substance and waste handling requirements. We believe that we are in substantial compliance with the requirements of CERCLA, OPA, RCRA, and other applicable federal and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our hazardous substances and wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Water Discharges
The Federal Water Pollution Control Act (the “Clean Water Act”), the Safe Drinking Water Act (“SDWA”), the OPA and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). In June 2015, the EPA and the Corps issued a rule to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, which never took effect before being replaced by the Navigable Waters Protection Rule (the “NWPR”) in April 2020. The NWPR was vacated by two separate federal district courts in late 2021. The definition of WOTUS was further impacted by the U.S. Supreme Court’s decision issued in May 2023 in Sackett v. EPA wherein the Court held that the jurisdiction of the Clean Water Act extends only to those adjacent wetlands that are indistinguishable from traditional navigable bodies of water due to a continuous surface connection and rejected the “significant nexus” test embraced in earlier jurisprudence. In September 2023, the EPA and the Corps published a direct-to-final rule redefining WOTUS to align with the decision in Sackett. The final rule eliminated the “significant nexus” test from consideration when determining federal jurisdiction and clarified that the Clean Water Act only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water. However, roughly half of the states and other plaintiffs are continuing to challenge the rule, and the EPA and the Corps are using the pre-2015 definition of WOTUS in these states while litigation continues. As a result, substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of storm water or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits or specify other requirements for discharges or operations that may impact groundwater conditions. These same regulatory programs may also limit the total volume of water that can be discharged, hence limiting the rate of development and requiring us to incur compliance costs. Additionally, we are required to develop and implement spill prevention, control and countermeasure plans, in connection with on-site storage of significant quantities of oil.
These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Additionally, obtaining permits has the potential to delay the development of natural gas and oil projects. We maintain all required discharge permits necessary to conduct our operations and we believe we are in substantial compliance with their terms.
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In addition, in some instances, the operation of underground injection wells for the disposal of wastewater has been alleged to cause earthquakes. For example, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. In some jurisdictions, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity or resulted in stricter regulatory requirements relating to the location and operation of underground injection wells. Such issues have also led to lawsuits by private parties alleging damages relating to induced seismicity. For example, the Railroad Commission of Texas (the “Commission”) requires applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey, which are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The Commission is authorized to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Commission is also considering new restrictions that could limit the volume and pressure of produced water injected into disposal wells. Additionally, we conduct oil and gas drilling and production operations in the Mississippian Lime formation in Oklahoma, a high-water play, which requires us to dispose of large volumes of saltwater generated as part of our operations. The Oklahoma Geological Survey attributed an increase in seismic activity in Oklahoma to saltwater disposal wells in the Arbuckle formation and, the Oklahoma Corporation Commission (the “OCC”), whose Oil and Gas Conservation Division regulates oil and gas operations in Oklahoma, issued regulations targeting saltwater disposal activities in certain areas of interest within the Arbuckle formation. The regulations include operational requirements (i.e., mechanical integrity testing of wells permitted for disposal of 20,000 or more barrels of water per day, daily monitoring and recording of well pressure and discharge volume), as well as orders to shut-in wells, reduce well depths, or decrease disposal volumes. Under these regulations, the OCC ordered us to limit the volume of saltwater disposed of in saltwater disposal wells in the Arbuckle formation, and it established caps for ten of our saltwater disposal wells, which caps are still in place. To ensure that we had an adequate number of wells for disposal, we secured permits for additional saltwater disposal wells outside of the Arbuckle formation. We are currently in compliance with all OCC saltwater disposal requirements and have maintained our production base without any negative material impact. However, any future orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect or curtail our operations.
Hydraulic Fracturing
We use hydraulic fracturing extensively in our onshore operations, but not our offshore operations. Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA’s wastewater pretreatment standards prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to environmental requirements may result in increased costs.
The BLM had previously issued a rule that would restrict hydraulic fracturing on federal and Indian lands, but the BLM rescinded that rule in December 2017, overruling the objections of several environmental groups and states that challenged rescission of the rule. In July 2023, legislation was introduced in Congress that would have given the EPA the authority to regulate hydraulic fracturing processes across the U.S. and require U.S. fracturing companies to publicly disclose the chemicals used in such process, but that legislation did not pass out of committee.
Several states have also adopted, or are considering adopting, regulations requiring the disclosure of the chemicals used in hydraulic fracturing and/or otherwise imposing additional requirements for hydraulic fracturing activities. For example, Oklahoma requires oil and gas producers to report the chemicals they use in hydraulic fracturing to FracFocus.org, a national hydraulic fracturing chemical registry, or to the OCC, which will convey the information to FracFocus.org. The Louisiana Department of Natural Resources has adopted rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. Also, Texas requires oil and natural gas operators to disclose to the Commission and the public the chemicals used in the hydraulic fracturing process, as well as the total volume of water used. Texas has also imposed requirements for drilling, putting pipe down and cementing wells, and testing and reporting requirements.
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Certain governmental reviews have been conducted that focus on environmental aspects of hydraulic fracturing practices, which could lead to increased regulation. For example, in 2016, the EPA issued a report examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. The EPA has also issued a report on onshore conventional and unconventional oil and gas extraction wastewater management, and conducted a study of private wastewater treatment facilities, also known as centralized waste treatment facilities, accepting oil and gas extraction wastewater. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated various other aspects of hydraulic fracturing. These studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
Additionally, a number of lawsuits and enforcement actions have been initiated across the country, alleging that hydraulic fracturing practices have induced seismic activity and adversely impacted drinking water supplies, use of surface water, and the environment generally. Several states (such as California) and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. We believe that we follow standard industry practices and legal requirements applicable to our hydraulic fracturing activities. Nonetheless, in the event of new or more stringent federal, state or local legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater or otherwise have negative impacts.
At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
Air Emissions
The federal Clean Air Act, as amended (“CAA”), and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. The South Coast Air Quality Management District (“SCAQMD”) is a regulatory subdivision of the State of California and is responsible for air pollution control from stationary sources within Orange County and designated portions of Los Angeles, Riverside, and San Bernardino Counties. Our Beta properties and associated facilities are subject to regulation by the SCAQMD. Federal, SCAQMD, and other state laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.
The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits.
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In November 2021, the EPA issued a proposed rule intended to establish standards for methane and volatile organic compounds, or VOCs, from new and modified oil and natural gas production and natural gas processing and transmission facilities. The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. The EPA announced a final rule in December 2023, which, among other things, requires the phase out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply.
Additionally, in 2016, the BLM finalized rules related to further controlling the venting and flaring of natural gas on BLM land, which was challenged by a group of states. In September 2018, the BLM published a final rule that revised the 2016 rules, which was again challenged by states and environmental groups. In April 2024, and later revised in November 2024, the BLM issued a final rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on Federal and Indian leases. In January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources. Consequently, future implementation and enforcement of the final 2023 EPA rule and the final 2024 BLM rule remain uncertain at this time.
We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.
Climate Change Regulation
At the international level, the United States joined the international community at the United Nations Framework Convention on Climate Change 21st Conference of the Parties (“COP21”) in Paris, France in 2015, which resulted in an agreement intended to nationally determine their contributions and set GHG emission reduction goals every five years beginning in 2020. In February 2021, the prior Biden Administration announced reentry of the U.S. into the Paris Agreement along with a new “nationally determined contribution” for U.S. GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030. Additionally, at the United Nations Framework Convention on Climate Change 28th Conference of the Parties (“COP28”), nearly 200 countries entered into an agreement that calls for actions towards achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts towards the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems. Most recently, at the 29th Conference of the Parties (“COP29”), delegates approved rules to operationalize international carbon markets under Article 6 of the Paris Agreement, including a new Paris Agreement Crediting Mechanism to trade UN-approved carbon credits. Additionally, participants at COP29 representing 159 countries met to review progress toward the goals of the Global Methane Pledge and the addition of nearly $500 million in new grant funding for methane abatement. However, in January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and any similar commitment made under the UN Framework Convention on Climate Change. However, various state and local governments in the U.S. have publicly committed to furthering the goals of the Paris Agreement. It is not possible at this time to predict how legislation or regulations that may be adopted to address climate change, methane and other GHG emissions may impact our business.
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In August 2022, the prior Biden Administration signed into law the Inflation Reduction Act. Among other things, the Inflation Reduction Act includes a methane emissions reduction program that amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain oil and gas sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit has commenced. In November 2024, the EPA finalized a regulation to implement the Inflation Reduction Act’s Waste Emissions Charge, which became effective on January 1, 2025. The fee imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 is $900 per ton emitted over annual methane emissions thresholds, and increases to $1,200 in 2025, and $1,500 in 2026. For the year ended December 31, 2024, the Company recognized $0.4 million in Waste Emission Charges.
At the state level, California enacted legislation in October 2023, further amended in 2024, that will ultimately require certain companies that do business in California and exceed specified financial thresholds to publicly disclose their Scopes 1, 2, and 3 GHG emissions, with third party assurance of such data, and issue public reports on climate-related financial risk and related mitigation measures. The implementing regulations for these laws are expected in 2025 and the requirements are currently set to begin taking effect on January 1, 2026, with additional requirements phasing in through 2030. The legislation on GHG emission disclosures in California is currently subject to legal challenge in federal court. While we are still assessing the impact of these requirements, additional reporting obligations could cause us to incur increased costs.
Additionally, on March 6, 2024, the SEC adopted new rules regarding the enhancement and standardization of climate-related disclosures for investors (the “SEC Climate Rules”). The SEC Climate Rules require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about material climate-related risks; the registrant’s governance of climate-related risks and relevant risk management processes; material climate-related targets and goals; and certain financial effects resulting from severe weather events and other natural conditions in a note to their audited financial statements (subject to de minimis thresholds). Larger registrants will also be required to disclose information about material Scope 1 and 2 greenhouse gas emissions, which will be subject to a phased-in assurance requirement. However, the SEC voluntarily stayed the SEC Climate Rules in April 2024 pending judicial review of petitions challenging the rules. We are currently evaluating the impact of the SEC Climate Rules and there remains uncertainty as to whether these rules will withstand pending and future legal challenges.
While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not currently adversely impacted by existing federal, state and local climate change initiatives. The adoption and implementation of any new regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. For example, any GHG regulation could increase our costs of compliance by requiring enhanced disclosure obligations, potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric driven compression at facilities to obtain regulatory permits and approvals in a timely manner. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
Moreover, any legislation or regulatory programs to reduce GHG emissions could increase the cost of consumption, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also reduce demand for the oil and natural gas we produce. However, the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. ends the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, and in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of federal climate change rules remain uncertain at this time.
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National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands are subject to NEPA. NEPA requires federal agencies, including the U.S. Departments of the Interior and Agriculture, to evaluate major federal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency evaluates the potential direct, indirect and cumulative impacts of a proposed project. If the proposed impacts are considered significant, the agency will prepare a detailed environmental impact statement that is made available for public review and comment. In July 2020, the White House’s Council on Environmental Quality (“CEQ”) published a final rule to amend the NEPA implementing regulations intended to streamline the environmental review process, including shortening the time for review as well as eliminating the requirement to evaluate cumulative impacts. The final rule required federal agencies to develop procedures consistent with the new rule within one year of the rule’s effective date (which was extended to two years in June 2021). In October 2021, the CEQ issued a notice of proposed rulemaking to amend the NEPA regulatory changes adopted in 2020 in two phases. Phase I of the CEQ’s proposed rulemaking process was finalized in April 2022, and generally restored provisions that were in effect prior to 2020. In May 2024, the CEQ finalized the Phase II rule that accelerates NEPA reviews while maintaining consideration of relevant environmental, environmental justice and climate change objectives. Further, the Infrastructure and Investment Jobs Act signed into law in November 2021 codified some of the July 2020 amendments in statutory text. These amendments must be implemented into each agency’s implementing regulations, and each of those individual rulemakings could be subject to legal challenge. Additionally, in June 2023, the Fiscal Responsibility Act of 2023 was signed into law, which includes important changes to NEPA to streamline the environmental review process. However, in January 2025, President Trump issued an executive order requiring CEQ to provide guidance on implementing NEPA and to propose rescinding CEQ’s NEPA regulations. The executive order also instructs federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews. In February 2025, CEQ sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our operations.
Endangered Species Act and Migratory Bird Treaty Act
The federal ESA was established to protect endangered and threatened species and their habitat. If a species is listed as threatened or endangered pursuant to the ESA, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (“FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. In January 2021, the Department of the Interior finalized a rule limiting the application of the MBTA. However, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department’s plan to develop regulations that authorize incidental taking under certain prescribed conditions. The future of this rulemaking is uncertain. In April 2024, the U.S. FWS issued three final rules governing critical habitat designation and expanding protection options for species listed as threatened pursuant to the ESA. However, in January 2025, President Trump issued an executive order declaring a national energy emergency and directing agency heads to identify actions to facilitate the energy supply that may be subject to emergency treatment, including under the ESA. Consequently, future implementation and enforcement of these rules remain uncertain at this time. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. The presence of protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and consequently, adversely affect our results of operations and financial position. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.
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Occupational Safety and Health Act
We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties. We believe that our operations are in substantial compliance with the OSHA requirements.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on our assets. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.
Legislation continues to be introduced in Congress, and the development of regulations continues in the U.S. Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
Drilling and Production
Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
● the location of wells;
● the method of drilling and casing wells;
● the surface use and restoration of properties upon which wells are drilled;
● the plugging and abandoning of wells;
● transportation and disposal of produced fluids and natural gas; and
● notice to surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
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Sale and Transportation of Gas and Oil
The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the construction and operations of interstate gas pipeline facilities and the rates, terms and conditions of service under which companies provide interstate transportation of gas, oil and other liquids by pipeline. Although the FERC does not have jurisdiction over the production of gas, the FERC exercises regulatory authority over wholesale sales of gas in interstate commerce through the issuance of blanket marketing certificates that authorize the wholesale sale of gas at market rates and the imposition of a code of conduct on blanket marketing certificate holders that regulate certain affiliate interactions. The FERC does not regulate the sale of oil or petroleum products or the construction of oil or other liquids pipelines, but does regulate the rates and terms and conditions of service on oil and liquids pipelines. The FERC also has oversight of the performance of wholesale natural gas markets, including the authority to facilitate price transparency and to prevent market manipulation. In furtherance of this authority, the FERC imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a minimum level. These agency actions have been intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.
The FERC and other federal agencies, the U.S. Congress or state legislative bodies and regulatory agencies may consider additional proposals or proceedings that might affect the gas or oil industries. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any such proposal will affect us any differently than it would affect other gas or oil producers with which we compete.
The Beta properties include the San Pedro Bay Pipeline Company, which owns and operates an offshore crude oil pipeline. This pipeline is subject to regulation by the FERC under the Interstate Commerce Act and the Energy Policy Act of 1992. Tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, must be just and reasonable and not unduly discriminatory. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with the FERC and posted publicly. The FERC has established a formulaic methodology for oil and liquids pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. During the last review period, FERC set the index level in December 2020. Both pipelines and pipeline customers sought rehearing of the index level, and in January 2022, FERC issued a rehearing order setting a lower index price, effective July 1, 2021, of the producer price index for finished goods minus 0.21%. Pipelines challenged this decision and on July 26, 2024, the D.C. Circuit vacated the rehearing order. Subsequently, on September 17, 2024, FERC issued an order reinstating the index price of producer price index for finished goods plus 0.78%. Then, on October 17, 2024, FERC issued a supplemental notice of proposed rulemaking proposing to reduce the index price back to the producer price index for finished goods minus 0.21%; that proposal is now pending at FERC. The San Pedro Bay Pipeline Company uses the indexing methodology to change its rates.
The Outer Continental Shelf Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. BOEM/BSEE has established formal and informal complaint procedures for shippers that believe they have been denied open and non-discriminatory access to transportation on the OCS.
The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates the safety of all pipeline transportation in or affecting interstate or foreign commerce, including pipeline facilities on the OCS. The San Pedro Bay pipeline is subject to regulation by the PHMSA. In recent years, PHMSA has been active in proposing and finalizing additional regulations for natural gas and hazardous liquids pipelines. For example, in January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to a high consequence area (“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. In addition, in April 2016, PHMSA proposed a rule regarding the safety of natural gas transmission pipelines and gas gathering pipelines. In October 2019, PHMSA issued a final rule on the natural gas transmission lines portion of the April 2016 rulemaking, and in November 2021 PHMSA issued a final rule on the gathering lines portion of the April 2016 rulemaking. Under the new final rule, operators of onshore natural gas gathering pipelines that were previously excluded from certain PHMSA regulations face additional testing, safety and reporting requirements or may be forced to reduce their allowable operating pressures, which would reduce the amount of capacity available to the Company. Certain reporting requirements arising from the new PHMSA rule took effect in 2022, with additional requirements taking effect later in 2023.
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Moreover, effective April 2017, the PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations. PHMSA updates the maximum administrative civil penalties each year to account for inflation, and as of December 2024, the penalty limits are up to $272,926 per violation per day and up to $2,729,245 for a related series of violations. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. In March 2022, PHMSA announced a final rule, effective October 5, 2022, to improve pipeline safety and reduce methane emissions by requiring the installation of remotely controlled or automatic shut-off valves, or similar technologies, in new and replaced onshore natural gas and other hazardous liquid pipelines. In August 2022, PHMSA passed a final rule, effective May 24, 2023, to protect the safety and environmental protection of onshore gas transmission pipelines, which establishes new standards for identifying threats, failures and worst-case scenarios throughout from initial failure through conclusion of an incident. Additionally, on January 17, 2025, PHMSA issued a final rule to implement congressional mandates to reduce methane leaks from new and existing natural gas transmission, distribution and gathering pipelines and liquefied natural gas facilities. The final rule will be effective 180 days after the date of publication in the Federal Register.
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.
Anti-Market Manipulation Laws and Regulations
The FERC, with respect to the purchase or sale of natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction and the Federal Trade Commission (the “FTC”) with respect to petroleum and petroleum products, operating under various statutes, have each adopted anti-market manipulation regulations, which prohibit, among other things, fraud and price manipulation in the respective markets. These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order repayment or disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Derivatives Regulation
Comprehensive financial reform legislation was signed into law by former President Obama on July 21, 2010 (the “Dodd-Frank Act”). This legislation called for the Commodities Futures Trading Commission (the “CFTC”) to regulate certain markets for derivative products, including over-the-counter derivatives. The CFTC has issued several new relevant regulations and rulemakings to implement the Dodd-Frank Act, the mandate to cause significant portions of derivatives markets to clear through clearinghouses, along with other mandated changes. While some of these rules have been finalized, some have not. As a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.
In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The CFTC’s final rules were challenged in court by two industry associations and were vacated and remanded by a federal district court. Subsequently, the CFTC proposed new rules in November 2013 and December 2016. In January 2020, the CFTC withdrew the 2013 and 2016 proposals. In January 2021 the CFTC issued a final rule on the matter, effective March 15, 2021. The final rule includes limits on positions in (1) certain “Core Referenced Futures Contracts,” including contracts for several energy commodities; (2) futures and options on futures that are directly or indirectly linked to the price of a Core Referenced Futures Contract, or to the same commodity for delivery at the same location as specified in that Core Referenced Futures Contract; and (3) economically equivalent swaps. The final rule also includes exemptions from position limits for bona fide hedging activities.
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The Dodd-Frank Act and new, related regulations may prompt counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may become less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations. Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.
Our sales of oil and natural gas are also subject to anti-manipulation and anti-disruptive practices authority under (i) the Commodity Exchange Act (the “CEA”), as amended by the Dodd-Frank Act, and regulations promulgated thereunder by the CFTC, and (ii) the Energy Independence and Security Act of 2007 (the “EISA”) and regulations promulgated thereunder by the FTC. The CEA, as amended by the Dodd-Frank Act, prohibits any person from using or employing any manipulative or deceptive device in connection with any swap, or a contract for sale of any commodity, or for future delivery on such commodity, in contravention of the CFTC’s rules and regulations. It also prohibits knowingly delivering or causing to be delivered false, misleading or inaccurate reports concerning market information or conditions that affect or tend to affect the price of any commodity. The FTC’s Petroleum Market Manipulation Rule, issued pursuant to EISA, prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. Under both the CEA and the EISA, fines for violations can be up to $1,000,000 per day per violation (subject to adjustment for inflation) and certain knowing or willful violations may also lead to a felony conviction.
Additional proposals and proceedings that may affect the crude oil and natural gas industry are pending before the U.S. Congress, federal agencies and the courts. The Company cannot predict the ultimate impact these proposals may have on its crude oil and natural gas operations, but the Company does not expect any such action to affect the Company differently than it will affect other gas or oil producers with which we compete.
State Regulation
Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, the baseline Texas severance tax on oil and gas is 4.6% of the market value of oil produced and 7.5% of the market value of gas produced and saved. A number of exemptions from or reductions of the severance tax on oil and gas production are provided by the State of Texas which effectively lowers the cost of production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Human Capital
Overview
On December 31, 2024, the Company had 229 employees, none of whom were represented by labor unions or covered by any collective bargaining agreement. We strive to create a high-performing culture and positive work environment that allows us to attract and retain a diverse group of talented individuals who can foster the Company’s success. To attract and retain top talent, our human resources programs are designed to reward and incentivize our employees through competitive compensation practices, our commitment to employee health and safety, training and talent development and our commitment to diversity and inclusion.
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Safety
Safety is our highest priority, and we are dedicated to the well-being of our employees, contractors, business partners, stakeholders and the environment. We promote safety with a robust health and safety program, which includes employee orientation and training, contractor management, risk assessment, hazard identification and mitigation, audits, incident reporting and investigation, and corrective and preventative action development.
In addition, we employ environmental, health and safety personnel at each of our asset locations, who provide in-person safety training and regular safety meetings. We also utilize learning management software to provide safety training on a variety of topics, and we contract with third-party technical experts to facilitate training on specialized topics that are unique to each of our areas of operation.
It is our policy to provide our employees with a safe and healthy workplace and to follow procedures aimed at safeguarding employees. We believe accident prevention and efficiency in production run hand-in-hand. Our internal Stop Work Authority empowers employees to pause operations so that an observed potential hazard can be eliminated or mitigated.
We are committed to maintaining a safe and healthy work environment by complying with state and federal regulations concerning the health and safety of our employees. Our employees are expected to demonstrate a cooperative spirit by working together to help us in this effort. As such, every employee is directly responsible for the proper care and use of Amplify property and equipment placed in their charge, either temporarily or on a regular basis.
Compensation
We operate in a highly competitive environment and have designed our compensation program to attract, retain and motivate talented and experienced individuals. Our compensation philosophy is designed to align the interests of our workforce with those of our stakeholders and to reward them for achieving the Company’s business and strategic objectives and driving shareholder value. We consider competitive market compensation paid by our peers and other companies comparable to us in size, geographic location and operations in order to ensure our compensation remains competitive and fulfills our goal of recruiting and retaining talented employees.
Training and Development
We are committed to the training and development of our employees. Employees are regularly provided training opportunities to develop skills in leadership, safety, and technical acumen, which bolsters our efforts in conducting business in a safe manner and with high ethical standards. Further, we believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We encourage our employees to advance their knowledge and skills and to network with other professionals in order to pursue career advancement and potential future opportunities with the Company. Our employees are able to attend training seminars and off-site workshops or to join professional associations that will enable them to remain up to date on the latest changes and best practices in their respective fields.
Diversity and Inclusion
We are committed to supporting a diverse and inclusive workplace and career development opportunities to attract and retain talented employees. As of December 31, 2024, approximately 15% of our total workforce self-identified as a racial or ethnic minority and approximately 16% self-identified as female. As of the same date, approximately 32% of the employees located in our corporate headquarters self-identified as a racial or ethnic minority and approximately 48% self-identified as female. We believe that a diverse workforce provides the opportunity to obtain unique perspectives, experiences, ideas, and solutions to help our business succeed. It is our policy to prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, national origin, age, disability, genetic information, veteran status, or any other basis protected by federal, state or local law. Further, it is our policy to forbid retaliation against any individual who reports, claims, or makes a charge of discrimination or harassment, fraud, unethical conduct, or a violation of our Company policies. To sustain and promote an inclusive culture, we maintain a robust compliance program rooted in our Code of Business Conduct and Ethics and other Company policies, which provide policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities. We require all employees to complete periodic training sessions on various aspects of our corporate policies through an annual acknowledgment and certification process.
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Health and Wellness
We support our employees and their families by offering a robust package of health and welfare benefits, medical, dental, and vision insurance plans for employees and their families, life insurance and long-term disability plans, paid time off for holidays, vacation, sick leave, and other personal leave, and health and dependent care savings accounts. We also provide our employees with a 401(k) plan that includes a competitive company match, and employees have access to a variety of resources and services to help them plan for retirement.
In addition to these programs, we have several other programs designed to further promote the health and wellness of our employees, including, among others, an employee assistance program that offers counseling and referral services for a broad range of personal and family situations.
The success of our business is fundamentally connected to the safety and well-being of our employees. Our focus remains on providing a safe office environment for our employees while continuing to allow for remote work, hybrid work and flexible work schedules where feasible. With the support of the varying work arrangements and a geographically dispersed workforce, we continue to develop ways to best support our people.
Offices
Our principal executive office is located at 500 Dallas Street, Suite 1700, Houston, Texas 77002. Our main telephone number is (832) 219-9001.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website at www.amplifyenergy.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. Our website also includes our Code of Business Conduct and Ethics, Corporate Governance Guidelines and the charters of our audit committee, compensation committee and nominating & governance committee. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
The SEC maintains a website that contains reports, proxy and information statements, and other information regarding the Company at www.sec.gov.
ITEM 1A.RISK FACTORS
Our business and operations are subject to many risks. The risks described below, in addition to the risks described in “Item 1. Business” of this Annual Report, may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. You should carefully consider the following risk factors together with all of the other information included in this Annual Report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report could have a material adverse effect on our business, financial position, results of operations and cash flows and the trading price of our securities could decline, and you could lose all or part of your investment.
Risks Related to Our Business
Oil, natural gas and NGL prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition.
Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:
● the regional, domestic and foreign supply of oil, natural gas and NGLs;
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● the level of commodity prices and expectations about future commodity prices;
● the level of global oil and natural gas exploration and production;
● the cost of exploring for developing, producing and transporting reserves;
● speculative trading in crude oil and natural gas derivative contracts;
● the level of consumer product demand;
● weather conditions and other natural disasters;
● risks associated with operating drilling rigs;
● domestic and foreign governmental regulations and taxes;
● the impact of energy conservation efforts;
● overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2024, the NYMEX-WTI oil future price ranged from a high of $122.11 per Bbl to a low of $(37.63) per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $9.68 per MMBtu to a low of $1.48 per MMBtu. For the year ended December 31, 2024, the WTI posted prices ranged from a high of $86.91 per Bbl on April 5, 2024 to a low of $65.75 per Bbl on September 10, 2024 and NYMEX-Henry Hub natural gas market price ranged from a high of $3.95 per MMBtu on December 24, 2024 to a low of $1.58 per MMBtu on February 15, 2024. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and different pricing characteristics, have sustained depressed realized prices during this period and are generally correlated with the price of oil. A further or extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition.
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If commodity prices decline for a prolonged period, a significant portion of our development projects may become uneconomic and result in write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and our ability to fund our operations.
Oil, natural gas and NGL prices have experienced significant volatility over the past few years. An extended decline in commodity prices could render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would reduce our borrowing base and our ability to fund our operations.
No impairment expense was recognized for the years ended December 31, 2024 and 2023. An extended decline in commodity prices may cause us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may in the future incur impairment charges that could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our Revolving Credit Facility.
Our business could be adversely affected by a decline in general economic conditions or a weakening of the broader energy industry, and inflation may adversely affect our financial position and operating results.
A prolonged economic slowdown or recession, adverse events relating to the energy industry, volatility due to tariffs or other trade-related disputes, or regional, national, or global economic conditions and factors, particularly a slowdown in the exploration and production industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased demand for oil and natural gas and decreased prices for oil and natural gas.
Inflationary factors, such as increases in the labor costs, material costs, and overhead costs, may also adversely affect our financial position and operating results. Inflation has also resulted in higher interest rates in the United States, which could increase our cost of debt borrowing in the future.
Loss of our key executive officers or other key personnel, or an inability to attract and retain such officers and personnel, could negatively affect our business.
Our future success depends on the skills, experience and efforts of our key executive officers. The sudden loss of any of these executives’ services or our failure to appropriately plan for any expected key executive succession could materially and adversely affect our business and prospects, as we may not be able to find suitable individuals to replace them on a timely basis, if at all. Additionally, we also depend on our ability to attract and retain qualified personnel to operate and expand our business. If we fail to attract or retain talented new employees, our business and results of operations could be negatively affected.
We may be unable to maintain compliance with the covenants in the Revolving Credit Facility, which could result in an event of default thereunder that, if not cured or waived, would have a material adverse effect on our business and financial condition.
Under our Revolving Credit Facility, we are required to (i) maintain, as of the date of determination, a maximum total debt to EBITDAX ratio of 3.00 to 1.00, (ii) maintain a current ratio of not less than 1.00 to 1.00, and (iii) hedge at least 50% − 75% of our estimated production from total proved developed producing reserves. If we were to violate any of the covenants under our Revolving Credit Facility and were unable to obtain a waiver or amendment, it would be considered a default after the expiration of any applicable grace period. If we were in default under our Revolving Credit Facility, then the lenders may exercise certain remedies including, among others, declaring all borrowings outstanding thereunder, if any, immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due, because we might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our Revolving Credit Facility are secured by mortgages on not less than 90% of the PV-9 value of our oil and gas properties together with all or substantially all material midstream assets necessary to operate our proved, developed and producing oil and gas properties, and if we are unable to repay our indebtedness under our Revolving Credit Facility, the lenders could seek to foreclose on our assets.
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Restrictive covenants in our Revolving Credit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Restrictive covenants in our Revolving Credit Facility impose significant operating and financial restrictions on us and our subsidiaries. These restrictions limit our ability to, among other things:
● incur additional liens;
● incur additional indebtedness;
● merge, consolidate or sell our assets;
● pay dividends or make other distributions or repurchase or redeem our stock;
● make certain investments; and
● enter into transactions with our affiliates.
Our Revolving Credit Facility also requires us to comply with certain financial maintenance covenants as discussed above. A breach of any of these covenants could result in a default under our Revolving Credit Facility. If a default occurs and remains uncured or unwaived, the administrative agent or majority lenders under our Revolving Credit Facility may elect to declare all borrowings outstanding thereunder, if any, together with accrued interest and other fees, to be immediately due and payable. The administrative agent or majority lenders under our Revolving Credit Facility would also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay our indebtedness when due or declared due, the administrative agent will also have the right to proceed against the collateral pledged to it to secure the indebtedness under our Revolving Credit Facility. If such indebtedness were to be accelerated, our assets may not be sufficient to repay in full our secured indebtedness.
We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants in our Revolving Credit Facility. The terms and conditions of our Revolving Credit Facility affect us in several ways, including:
● limiting management’s discretion in operating our business.
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Our lenders periodically redetermine the amount we may borrow under our Revolving Credit Facility, which may materially impact our operations.
Our Revolving Credit Facility allows us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The borrowing base is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. Accordingly, declining commodity prices may have an impact on the amount we can borrow, which could affect our cash flows and ability to execute our business plans. Any material reduction in the borrowing base would materially and adversely affect our business and financing activities, limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on our debt obligations. In addition, as hedges roll off, the borrowing base is subject to further reduction. Our Revolving Credit Facility requires us to repay any deficiency over a certain period or pledge additional oil and gas properties to eliminate such deficiency within 30 days of notice. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the Revolving Credit Facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under our Revolving Credit Facility.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our Revolving Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.
Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.