Amplify Energy Corp. [AMPY] Filings

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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For the fiscal year ended December 31, 2022

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For the transition period from                      to                     .

Commission File Number: 001-35512

AMPLIFY ENERGY CORP.

(Exact name of registrant as specified in its charter)

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Registrant’s telephone number, including area code: (832) 219-9001

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Securities Registered Pursuant to Section 12(b) of the Act:

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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). Yes  þ    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.

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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 $231.2 million on June 30, 2022, based on $6.54 per share, the last reported sales price of the shares on the New York Stock Exchange on such date.

As of February 28, 2023, the registrant had 38,710,696 outstanding shares of common stock, $0.01 par value per share.

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AMPLIFY ENERGY CORP.

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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: A 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.

Bbl/d: One Bbl per day.

Bcfe: One billion cubic feet of natural gas equivalent.

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. As examples, 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 or Dry Well: 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.

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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.

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

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.

MBbls/d: One thousand Bbls per day.

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.

MMcfe/d: One MMcfe per day.

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.

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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.

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 U.S. Securities Exchange Commission (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: 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

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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.

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 2022 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 that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

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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:

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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 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, 2022:

Industry Trends

During 2022, activity in the global economy increased and demand for oil, natural gas and NGLs and related commodity pricing improved. As such, oil, natural gas and NGLs prices increased during 2022 when compared to 2021 and, as a result, the Company experienced an increase in revenues. The Company expects activity levels in 2023 will continue to increase, although not likely at the same rate as 2022.

The war in Ukraine, the COVID-19 pandemic, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and recent measures to combat persistent inflation have continued to contribute to economic and pricing volatility during 2022. Inflation in the U.S. has been rising at its fastest rate in over 40 years, creating inflationary pressure on the cost of services, equipment and other goods in the energy industry and other sectors, which is contributing to labor and materials shortages across the supply-chain. Additionally, the Organization of the Petroleum Exporting Countries and other large producing nations continue to meet regularly to evaluate the state of global oil supply, demand, and inventory levels. As such, pricing may remain volatile during 2023.

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Recent Developments

Pipeline Incident Settlement

On March 1, 2023, the Company announced that the vessels that struck and damaged the Pipeline and their respective owners and operators have agreed to pay the Company $96.5 million in a settlement. The Marine Exchange of Los Angeles-Long Beach Harbor (“Marine Exchange”) has agreed to non-monetary terms as well. The overall resolution includes subrogation claims by Amplify’s property damage and loss of production insurers, with Amplify ultimately receiving a net payment of approximately $85 million. The parties are working to finalize the settlement agreement documentation. The settlement resolves Amplify’s affirmative claims related to the Incident. As part of the settlement, after payment is made, Amplify will dismiss all of its legal claims against those parties. For a discussion regarding the Incident, see Note 15 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.

Borrowing Base Redetermination Agreement and Seventh Amendment

On December 9, 2022, OLLC (the “Borrower”) entered into the Borrowing Base Redetermination Agreement and Seventh Amendment to Credit Agreement, among the Borrower, Amplify Acquisitionco LLC, a Delaware limited liability company (“Acquistionco”), the guarantors party thereto, the lenders party thereto and KeyBank National Association, as administrative agent (the “Seventh Amendment”). The Seventh Amendment amends the parties’ existing Credit Agreement, dated as of November 2, 2018 (the “Credit Agreement”), to, among other things:

Director and Certain Officer Departures and Appointments

On February 27, 2023, Jason McGlynn notified the Company of his decision to resign. Mr. McGlynn will cease to serve as Chief Financial Officer of the Company effective March 17, 2023 (the “Separation Date”). Mr. McGlynn’s decision to resign stems solely from personal reasons and did not result from any disagreement with the Company or the board of directors.

Subject to Mr. McGlynn’s execution and non-revocation of a general release of claims and continued employment by the Company until the Separation Date, Mr. McGlynn’s 8,334 unvested time-based restricted stock units scheduled to vest on April 1, 2023 pursuant to the applicable award agreement will vest in full on the Separation Date.

On November 29, 2022, Richard P. Smiley notified the Company of his intent to retire and resign from his current position as Senior Vice President, Operations, which decision stemmed solely from personal reasons and did not result from any disagreement with the Company or any matter relating to the Company’s operations, policies or practices. Mr. Smiley intends to remain in his role at the Company to assist with an orderly transition of his responsibilities, and to continue to provide essential transition services to the Company following his retirement.

Effective December 31, 2022, Eric T. Greager resigned from the Company’s board of directors to pursue another career opportunity. Mr. Greager’s decision to leave the Company for another career opportunity was not a result of any disagreement with the Company or its board of directors or any matter relating to the Company’s financials, operations, policies or practices.

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On February 9, 2023, the Company’s board of directors appointed James E. Craddock to the board of directors. Mr. Craddock has also been appointed to the nominating and governance committee of the board of directors.

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, 2022. 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, 2022, and our average net production for the three months ended December 31, 2022:

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Our Areas of Operation

Oklahoma

Approximately 28% of our estimated proved reserves as of December 31, 2022 and approximately 32% of our average daily net production for the three months ended December 31, 2022 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 35.0 MMBbls of estimated net proved reserves as of December 31, 2022 based on our reserve report and generated average net production of 6.6 MBoe/d for the three months ended December 31, 2022.

Rockies (Bairoil)

Approximately 23% of our estimated proved reserves as of December 31, 2022 and approximately 18% of our average daily net production for the three months ended December 31, 2022 were located in the Rockies region. Our Rockies properties include wells and properties primarily located in the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Rockies properties contained 28.4 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2022 based on our reserve report and generated average net production of 3.7 MBoe/d for the three months ended December 31, 2022.

Southern California (Beta)

For a discussion regarding the Incident, see Note 15 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information.

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Approximately 11% of our estimated proved reserves as of December 31, 2022 were associated with the Beta field located in federal waters offshore Southern California approximately 11 miles offshore from the Port of Long Beach, California (“Beta”). 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 13.7 MMBbls of estimated net proved oil reserves as of December 31, 2022 based on our reserve report. 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 burned 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.

East Texas / North Louisiana

Approximately 35% of our estimated proved reserves as of December 31, 2022 and approximately 45% of our average daily net production for the three months ended December 31, 2022 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 43.9 MMBoe of estimated net proved reserves as of December 31, 2022 based on our reserve report and generated average net production of 9.5 MBoe/d for the three months ended December 31, 2022.

Eagle Ford (Non-Op)

Approximately 2% of our estimated proved reserves as of December 31, 2022 and approximately 5% of our average daily net production for the three months ended December 31, 2022 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 2.9 MMBoe of estimated net proved reserves as of December 31, 2022 based on our reserve report. Those properties collectively generated average net production of 1.1 MBoe/d for the three months ended December 31, 2022.

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.

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Mr. Lopez has over 16 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 is the President of CG&A 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 and the Society of Petroleum Evaluation Engineers.

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, 2022, which are based on the prepared reserve report by CG&A, our independent reserve engineers.

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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.”

Development of Proved Undeveloped Reserves

As of December 31, 2022, we had 1,058 MBoe of proved undeveloped reserves (“PUDs”) comprised of 858 Mbbls of oil, 607 MMcf of natural gas and 98 Mbbls of NGLs. None of our proved undeveloped reserves as of December 31, 2022 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, 2022, total proved undeveloped reserves decreased by 1,109 MBoe. The majority of this decrease (954 Mboe) was due to transfers to proved developed reserves on certain non-operated properties in Eagle Ford and Cotton Valley. Other changes (155 Mboe) include modifications to the non-operated development timing in the Eagle Ford.

Approximately 44.1% (954 MBoe) of our PUDs recorded as of December 31, 2021 were developed during the twelve months ended December 31, 2022. Total costs incurred to develop these PUDs were approximately $3.4 million, of which $0.9 million was incurred in fiscal year 2021 and $2.5 million incurred in fiscal year 2022. In total, we incurred total capital expenditures of approximately $4.6 million during fiscal year 2022 developing PUDs, which includes $2.1 million associated with PUDs to be completed in 2023. 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.”

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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, 2022 and 2021, respectively:

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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, 2022.

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Developed Acreage

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2022, substantially all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2022 relating to our leasehold acreage.

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Undeveloped Acreage

The following table sets forth information as of December 31, 2022 relating to our undeveloped leasehold acreage, which are held by production (including the remaining terms of leases and concessions).

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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, 2022, 9 gross (0.5 net) wells were in various stages of completion.

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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.

We have a long-term contract associated with our NGL production in Oklahoma with a third-party midstream service provider that is subject to a volume obligation. Information regarding our delivery commitments under these contracts is contained in Note 16 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data,” contained herein.

Operations

General

As of December 31, 2022, 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 or other oil field services equipment used for drilling or maintaining 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:

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