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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K10–K

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20172020

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.AMPLIFY ENERGY CORP.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (918) 947-8550(713) 490-8900

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

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

Indicate by check mark if the registrant is a well-knownwell–known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  o☐    No  x☑

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  o☐    No  x☑

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  x☑    No  o☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes  x☑    No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to the Form 10-K x

☐

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,”company” and “emerging growth company” in Rule 12b-212b–2 of the Exchange Act. Check one:

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. o☐

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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  o☐    No  x

☑

The aggregate market value of the registrant’s Common Stockvoting and non-voting common equity held by non-affiliates of the registrant was approximately $146.8$33.2 million based upon the closing price of such stock on June 30, 2017,2020, based on $1.23 per share, the last business dayreported sales price of the shares on the New York Stock Exchange on such date.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes  ☑   No  ☐

As of February 26, 2021, the registrant had 37,943,167 outstanding shares of Common Stock, $0.01 par value per share.

Documents Incorporated By Reference: Portions of the registrant’s most recently completed second fiscal quarter, of $12.67 per share.

The number of shares outstanding of our stock at March 8, 2018 is shown below:

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of Midstates Petroleum Company, Inc. for theproxy statement relating to its 2021 Annual Meeting of Shareholders to be held in June 2018,Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year,December 31, 2020, are incorporated by reference intoto the extent set forth in Part III, Items 10-14 of this Annual Report on Form 10-K.

AMPLIFY ENERGY CORP.

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Table of Contents

MIDSTATES PETROLEUM COMPANY, INC.

TABLE OF CONTENTS

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements other than statements of historical fact included in this annual report are forward-looking statements, including, without limitation, statements regarding our strategy, future operations, financial position, estimated revenues and income/loss, projected costs, prospects, plans and objectives of management. When used in this annual report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

·                  business strategy, including our business strategy post-emergence from our Chapter 11 cases (the “Chapter 11 Cases”);

·                  estimated future net reserves and present value thereof;

·                  technology;

·                  financial condition, revenues, cash flows and expenses;

·                  levels of indebtedness, liquidity, borrowing capacity and compliance with debt covenants;

·                  financial strategy, budget, projections and operating results;

·                  oil and natural gas realized prices;

·                  timing and amount of future production of oil and natural gas;

·                  availability of drilling and production equipment;

·                  the amount, nature and timing of capital expenditures, including future development costs;

·                  availability of oilfield labor;

·                  availability of third party natural gas gathering and processing capacity;

·                  availability and terms of capital;

·                  drilling of wells, including our identified drilling locations;

·                  successful results from our identified drilling locations;

·                  marketing of oil and natural gas;

·                  the integration and benefits of asset and property acquisitions or the effects of asset and property acquisitions or dispositions on our cash position and levels of indebtedness;

·                  infrastructure for salt water disposal and electricity;

·                  current and future ability to dispose of salt water;

·                  sources of electricity utilized in operations and the related infrastructures;

·                  costs of developing our properties and conducting other operations;

·                  general economic conditions;

·                  effectiveness of our risk management activities;

·                  environmental liabilities;

·                  counterparty credit risk;

·                  the outcome of pending and future litigation;

·                  governmental regulation and taxation of the oil and natural gas industry;

·                  developments in oil and natural gas producing countries;

·                  new capital structure;

·                  uncertainty regarding our future operating results; and

·                  plans, objectives, expectations and intentions contained in this annual report that are not historical.

All forward-looking statements speak only as of the date of this annual report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this annual report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and elsewhere in this annual report.

These factors include:

·                  variations in the market demand for, and prices of, oil, natural gas liquids (“NGLs”) and natural gas;

·                  uncertainties about our estimated quantities of oil and natural gas reserves;

·                  the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our reserves based revolving credit facility (the “Exit Facility”);

·                  access to capital and general economic and business conditions;

·                  uncertainties about our ability to replace reserves and economically develop our current reserves;

·                  risks in connection with acquisitions;

·                  risks related to the concentration of our operations onshore in Oklahoma and Texas;

·                  drilling results;

·                  the potential adoption of new governmental regulations, including future regulations regarding the disposal of salt water; and

·                  our ability to satisfy future cash obligations and environmental costs.

These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserves estimate depends on the quality of available data (including geoscience and engineering data), the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any future production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

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.

Bbl: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, ofor 42 U.S. gallons liquid volume, used herein in reference to oil condensate or natural gas liquids.other liquid hydrocarbons.

Bbl/d: One Bbl per day.

Boe:  Barrels of oil equivalent, with 6,000Bcfe: One billion cubic feet of natural gas being equivalent to oneequivalent.

Boe: One barrel of oil.

Boe/day:  Barrels of oil equivalent, per day.

Completion:  The processcalculated by converting natural gas to oil equivalent barrels at a ratio of treating a drilled well followed by the installation of permanent equipment for the productionsix 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.

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 casequality and/or location of a dry hole, the reporting of abandonment to the appropriate agency.oil or natural gas.

Dry hole: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 do notwould 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 are 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:Well: A well drilled to find a new field orand 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 or oil 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.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

ICE: Inter-Continental Exchange.

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MMBoe:One million barrels of oil equivalent.

Mcf: One thousand cubic feet of natural gas.

MMBtu: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:  The percentage of total acres an owner has out of a particular number ofAcres or Net Wells: Gross acres or a specified tract.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.

NYMEX: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.

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 reserves:Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

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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—producible, from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—regulations, prior to the time at which contracts providing the right to drill or 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 which can be produced economically through application of improved recovery techniques (including but not limited to, fluid injection) are included in the proved classification when (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 12-monthtwelve-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 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.

Reasonable certainty:  A high degreeRealized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of confidence.

Recompletion:  The process of re-entering an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is either producinga grouping of one or not producingmore technologies (including computational methods) that has been field-tested and completing new reservoirshas been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an attemptanalogous 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 establish, re-establishing, or increase existing production.reflect property acquisitions and dispositions.

Reserves:  EstimatedReserves: 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: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 reservoirs.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.

SpudSpacing: 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.

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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 Spudding:  The commencementstandards established by the SEC and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of drilling operationsthe date of estimation), less 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 new well.point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore: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:  TheInterest: An interest in an oil and natural gas lease that gives the owner of the interest the right granted to the lessee of a property to exploredrill for and to produce oil and own oil, natural gas or other minerals. The working interest owners bearon the exploration, development,leased acreage and operatinggenerally requires the owner to pay a share of the costs of drilling and production operations.

Workover: Operations on a cash, penalty,producing well to restore or carried basis.

PART Iincrease production.

WTI: West Texas Intermediate.

ITEM 1.  BUSINESS4

NAMES OF ENTITIES

As used in this Form 10-K, unless we indicate otherwise:

FORWARD–LOOKING STATEMENTS

General

Midstates Petroleum Company, Inc. is an independent exploration and production company focused on the application of modern drilling and completion techniques in oil and liquids-rich basins in the onshore United States. Our operations are concentrated in Oklahoma and Texas, with our corporate headquarters located in Tulsa, Oklahoma. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub” or “Debtor Affiliate”). In thisThis Annual Report referenceson Form 10-K contains forward-looking statements that are subject to “Company,a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

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,” “we,“Item 1A. Risk Factors,” “us,” “our,”“Item 7. Management’s Discussion and “Midstates” when used in the present tense, prospectively or for historical periods, refer to Midstates Petroleum Company, Inc.Analysis of Financial Condition and its wholly owned subsidiary.

On April 30, 2016, we filed voluntary petitions for reorganization under Chapter 11Results of the United States Bankruptcy Code. On October 21, 2016, in connection with our emergence from Chapter 11, our existing common shares were cancelled and on October 24, 2016, our new common shares issued in connection with our successful reorganization and emergence from Chapter 11 were listed and began trading on the NYSE MKT under the symbol “MPO”. Our common stock began trading on the NYSE under the symbol “MPO” beginning on May 4, 2017. We currently lease office space in Tulsa, Oklahoma at 321 South Boston Avenue, Suite 1000, where our principal offices are located. The lease for our Tulsa office expires in 2026. We also lease one field office in Dacoma, Oklahoma and one in Perryton, Texas. As of December 31, 2017, we had 129 employees.

We are required to file annual, quarterly and current reports, proxy statementsOperations” and other information with the Securities and Exchange Commission (“SEC”). You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

We also make available on our website (http://www.midstatespetroleum.com) all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Financial Code of Ethics, and the charters of our audit committee, compensation committee and nominating and governance committee are also available on our website and in print free of charge to any stockholder who requests them. Requests should be sent by mail to 321 South Boston Avenue, Suite 1000; Tulsa, Oklahoma 74103, attention Vice President — General Counsel. Information contained on our website is not incorporated by reference intoitems within this Annual Report on Form 10-K. 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 our 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 forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our 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 our 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 will disclosedo not intend to update or revise any amendmentsforward-looking statements as a result of new information, future events or waiversotherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our 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 categories of risks, including risks related to our Codebusiness and industry, risks related to information technology, data security and privacy, risks related to legal, regulatory, accounting, and tax matters, risks related to our Common Stock, and risks related to our Revolving Credit Facility, which are discussed more fully below. As a result, this risk factor summary does not contain all of Ethics on our website.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:

Business Strategy

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PART I

References

Our goal is to grow shareholder value through optimized capital investments and generation of free cash flow. To achieve these objectives, we strive to:

·                  Operate in a safe and environmentally responsible manner;

·                  Maximize our return on capital deployed by utilizing our extensive technical and operating experience in our core areas of operations to focus on identifying opportunities to achieve the best rate of return and the highest probability of success;

·                  Maintain a best in class cost structure to maximize the cash flow margin of our production;

·                  Prioritize free cash flow generation over production growth. Strive towards the optimum balance between free cash flow generation and sustaining inventory for future investment. We will optimize free cash flow generation by focused capital investments, optimizing our base production, and maintaining a low-cost structure; and

·                  Maintain maximum optionality by maintaining low net debt, balancing shareholder cash returns with replenishing inventory, and evaluating strategic alternatives within and outside of our current asset base.

Our balance sheet and strong liquidity position provide us with significant resources to develop our multi-year drilling inventory and judiciously expand our core acreage positions. For 2018, we intend to opportunistically achieve the best return on investments by optimizing our drilling and completion design, focusing on minimizing well down time and optimizing well productivities while maintaining both capital discipline and a low-cost structure.

Chapter 11 Plan of Reorganization

On April 30, 2016 (the “Petition Date”), we filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered under the case styled In reAugust 6, 2019, Midstates Petroleum Company, Inc., et al., Case No. 16-32237. On September 28, 2016, the Bankruptcy Court entered the Findings of Fact, Conclusions of Law, and Order Confirming Debtors’ First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate (the “Confirmation Order”a Delaware corporation (“Midstates”), which approved and confirmed the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. andcompleted its Debtor Affiliate as filed on the same datebusiness combination (the “Plan”“Merger”). On October 21, 2016 (the “Effective Date” with Amplify Energy Corp., a Delaware corporation (“Legacy Amplify”), we satisfied the conditions to effectiveness set forth in the Confirmation Order and in the Plan, the Plan became effective in accordance with the terms of that certain Agreement and Plan of Merger, dated May 5, 2019 (the “Merger Agreement”), by and among Midstates, Legacy Amplify and Midstates Holdings, Inc., a Delaware corporation and direct, wholly owned subsidiary of Midstates (“Merger Sub”). Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates, and immediately following the Merger, Legacy Amplify merged with and into Alpha Mike Holdings LLC, a Delaware limited liability company and wholly owned subsidiary of Midstates (“LLC Sub”), with LLC Sub surviving as a wholly owned subsidiary of Midstates. On the effective date of the Merger, Midstates changed its termsname to “Amplify Energy Corp.” (the “Company”) and we emerged fromLLC Sub changed its name to “Amplify Energy Holdings LLC.”

For financial reporting purposes, the Chapter 11 Cases. Further information is set forth in “—Note 2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings”Merger represented a “reverse merger” and Legacy Amplify was deemed to be the accounting acquirer in the Notestransaction. Legacy Amplify’s historical results of operations replaced Midstates’ historical results of operations for all periods prior to the Consolidated Financial Statements set forthMerger and, for all periods following the Merger, the Company’s financial statements reflect the results of operations of the combined company. Accordingly, the financial statements for the Company included in Part IV, Item 15 of this Annual Report for periods prior to the Merger are not the same as Midstates prior reported filings with the SEC, which were derived from the operations of Midstates. The results of any one quarter should not be relied upon as an indication of future performance.

When referring to Legacy Amplify, the intent is to refer to Amplify Energy Corp. prior to the Merger, and its consolidated subsidiaries as a whole or on Form 10-K.

Upon our emergencean individual basis, depending on the Effective Date, we adopted fresh start accounting as required by United States generally accepted accounting principles (“US GAAP”). We qualified for fresh start accounting because (i)context in which the holdersstatements are made. Legacy Amplify is the successor reporting company of existing voting sharesMemorial Production Partners LP pursuant to Rule 15d-5 of the pre-emergence debtor-in-possession received less than 50%Securities Exchange Act of 1934, as amended (the “Exchange Act”).

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, federal waters offshore Southern California, East Texas/North Louisiana, and Eagle Ford. 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, 2020:

Industry Trends

In March 2020, the World Health Organization declared a global pandemic related to the proliferation of COVID-19. The impact of COVID-19 and efforts to mitigate its spread have caused significant volatility in U.S. and international markets and a substantial reduction in global and domestic demand for oil and natural gas. Actions by governmental authorities to mitigate the spread of COVID-19, such as imposing mandatory closures of all non-essential business facilities, seeking voluntary closures of business facilities, and imposing restrictions on, or advisories with respect to, travel, business operations and public gatherings or interactions, have further exacerbated the economic impact of the voting shares of the post-emergence successor entity and (ii) the reorganization value of our assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. We applied fresh start accounting as of October 21, 2016. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares in the reorganized Company caused a related change of control under US GAAP. pandemic.

As a result of the applicationpandemic, there has also been a sharp reduction in the demand for oil and natural gas and a precipitous decline in commodity prices, which were further impacted by disputes over production levels among oil-producing countries, the significant increase in production levels by such countries and limited storage capacity for natural gas, oil and refined products.

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In response to the unprecedented and extremely low commodity prices, the Company executed several liquidity enhancement initiatives to better position the Company through the downturn, including significant decreases to operating and G&A expenses, substantial reductions to capital programs, the monetization of fresh start accounting,a portion of the Company’s 2021 in-the-money crude oil hedges, the receipt of loan proceeds from the federal government’s Paycheck Protection Program, royalty relief at the Company’s Beta Properties (defined below) and the suspension of the quarterly dividend, among other things. The successful realization and execution of our liquidity enhancing initiatives, coupled with a disciplined commodity hedging program, have substantially mitigated the impact of the pandemic on the Company’s operational and financial results and demonstrated the sustainable value of our long-lived, low-decline assets.

Despite the gradual recovery in commodity prices in the second half of 2020 and the expectation of a successful phased rollout of a vaccine in 2021, we have continued our commitment to operating in a disciplined, capital efficient manner, and we remain committed to the responsible stewardship of our assets and to continue focusing on maximizing cash flows, further reducing debt, delivering low-cost capital efficient operations, and generating shareholder value. We will continue to monitor developments regarding the pandemic, the distribution of the vaccination and changes in market conditions as wellwe pursue our business and strategic objectives.

Recent Developments

Appointment of Chief Executive Officer and Director

On January 19, 2021, the Company appointed Mr. Martyn Willsher as the effectsCompany’s President and Chief Executive Officer and member of the implementationboard of directors. Mr. Willsher had served as the Company’s Interim Chief Executive Officer since April 3, 2020 and Senior Vice President and Chief Financial Officer since April 27, 2018.

Appointment of Senior Vice President and Chief Financial Officer

On January 19, 2021, the Company appointed Mr. Jason McGlynn as the Company’s Senior Vice President and Chief Financial Officer. Mr. McGlynn had served as the Company’s Vice President of Business Development since February 3, 2020.

Resignation of Chairman of the Plan, our consolidated financial statements on or after October 21, 2016, are not comparableBoard of Directors

On January 19, 2021, Mr. David H. Proman announced his resignation from his position as Chairman of the board of directors of the Company. Mr. Proman retained his seat as a member of the board of directors.

Appointment of Chairman of the Board of Directors

Concurrently with our consolidated financial statements prior to that date. References to “Successor Period” relateMr. Proman’s resignation, the board of directors unanimously approved and appointed Mr. Christopher W. Hamm as the Company’s new Chairman of the board of directors.

Appointment of Director to the financial positionBoard of Directors

On February 10, 2021, Ms. Patrice Douglas was appointed as a member of the Company’s board of directors and resultswill also serve on the Company’s audit committee.

Secondary Public Offering of operationsCommon Stock for the period October 21, 2016 throughSelling Stockholders

On December 31, 2016 and references to “Predecessor Period” refer to the financial position and results of operations11, 2020, certain selling stockholders of the Company (the “Selling Stockholders”), Roth Capital Partners, LLC (the “Underwriter”) and the Company entered into an underwriting agreement, pursuant to which the Selling Stockholders agreed to sell to the Underwriter, and the Underwriter agreed to purchase from the Selling Stockholders, subject to and upon the terms and conditions set forth therein, an aggregate of 8,548,485 shares of common stock, par value $0.01 per share of the Company (“Common Stock”). The offering closed on December 15, 2020. The Company did not receive any proceeds from the sale of shares of Common Stock in the offering.

The offering was made pursuant to effective shelf registration statements (File No. 333-233677, effective October 11, 2019, and 333-215602, effective May 1, 2018) and prospectuses filed by the Company with the SEC. The offering of these securities was made only by means of a prospectus and prospectus supplement.

Borrowing Base Redetermination

On November 18, 2020, as part of the Company’s fall 2020 semiannual borrowing base redetermination, the borrowing base and lender commitments under the Company’s credit agreement among wholly owned subsidiaries of the Company, Bank of Montreal, as administrative agent, and other lenders party thereto (as amended from time to time, the “Revolving Credit Facility”) reaffirmed the borrowing base at $260.0 million, with the next such redetermination scheduled for spring 2021. The Revolving Credit Facility is a reserve-based revolving credit facility with a maturity date of November 2, 2023, and semiannual borrowing base redeterminations.

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Notice of Non-Compliance with New York Stock Exchange (“NYSE”) Continued Listing Standards

On August 31, 2020, the Company, received written notification (the “Market Cap Notice”) from the NYSE that the Company no longer satisfied the continued listing compliance standards set forth under Section 802.01B of the NYSE Listed Company Manual (the “Manual”) because the average global market capitalization of the Company was less than $50,000,000 over a consecutive 30 trading-day period that ended on August 28, 2020 and, at the same time, the Company’s stockholders’ equity was less than $50,000,000 (the “Market Cap Deficiency”).

Under NYSE procedures, the Company had 45 days from its receipt of the Market Cap Notice to submit a plan to the NYSE demonstrating how it intends to regain compliance with the NYSE’s continued listing standards within 18 months. The Company submitted its plan to regain compliance with the listing standards within the required timeframe.

In addition, on October 13, 2020, the Company received written notification (the “Share Price Notice”) from the NYSE that the Company no longer satisfied the continued listing compliance standards set forth under Section 802.01C of the Manual because the average closing price of the Company’s Common Stock was below $1.00 over a 30 consecutive trading-day period that ended October 12, 2020 (the “Share Price Deficiency”). Under the NYSE’s rules, the Company had six months following receipt of the Share Price Notice to regain compliance with the minimum share price requirement.

The Company notified the NYSE of its intent to cure the Share Price Deficiency and return to compliance with the NYSE’s continued listing requirements. On January 1, 2016 through October 20, 2016.4, 2021, the Company received written notification from the NYSE that the Company regained compliance with the NYSE’s continued listing standards. The Company regained compliance after its average closing price for the 30 trading-day period ended December 31, 2020 and its closing price on December 31, 2020 both exceeded $1.00 per share.

Under NYSE rules, the Common Stock will continue to be listed on the NYSE during the cure period related to the Market Cap Deficiency, subject to the Company’s compliance with other continued listing requirements. The Common Stock’s trading symbol “AMPY” was assigned a “.BC” indicator by the NYSE to signify that the Company currently is not in compliance with the NYSE’s continued listing requirements. If the Company fails to regain compliance with Sections 802.01B of the Manual during the cure period, the Common Stock will be subject to the NYSE’s suspension and delisting procedures.

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, 2020 and 2019. 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, 2020 and our average net production for the three months ended December 31, 2020:

Summary

Our Areas of Oil and Gas Properties and OperationsOperation

Oklahoma

Mississippian Lime

Our Mississippian Lime assets are located in Oklahoma and target the Mississippian Lime formation. At December 31, 2017, our acreage consisted of approximately 97,762 net (117,451 gross) prospective acres in the Mississippian Lime trend in Woods and Alfalfa Counties of Oklahoma, which we currently intend to develop using horizontal wells.

Our properties in this area represented 92%Approximately 34% of our totalestimated proved reserves as of December 31, 2017. As2020 and approximately 28% of December 31, 2017, we held anour average working interest and averagedaily net revenue interest of 77% and 62%, respectively, in this area.

Forproduction for the yearthree months ended December 31, 2017, the Successor Period and the Predecessor Period, our average daily production from our Mississippian Lime assets was as follows:

At December 31, 2017, we had one operated drilling rig in operation2020 were located in the Mississippian Lime horizontal well program. For 2018, we anticipate investing between $100.0 millionOklahoma region. Our Oklahoma properties include wells and $120.0 million in the area.

Anadarko Basin

Our Anadarko Basin assets areproperties primarily located in Western OklahomaAlfalfa and the Texas panhandle and target, or are prospectiveWoods counties in the Cleveland, Marmaton, Cottage Grove, Osage, Meramac and Tonkawa formations. At December 31, 2017, our acreage consistedOklahoma. Those properties collectively contained 39.3 MMBbls of approximately 76,409estimated net (92,289 gross) acres in Texas and 16,198 net (41,332 gross) acres in western Oklahoma.

Our properties in this area represented 8% of our total proved reserves as of December 31, 2017. As2020 based on our reserve report and generated average net production of 7.5 MBoe/d for the three months ended December 31, 2020.

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Rockies

Approximately 19% of our estimated proved reserves as of December 31, 2017, we held an2020 and approximately 15% of our average daily net production for the three months ended December 31, 2020 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 21.2 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2020 based on our reserve report and generated average net production of 4.0 MBoe/d for the three months ended December 31, 2020.

California

Approximately 15% of our estimated proved reserves as of December 31, 2020 and approximately 14% of our average daily net production for the three months ended December 31, 2020 were located in federal waters offshore Southern California. These properties (the “Beta Properties”) consist of: 100% of the working interestinterests and currently 87.6% average net revenue interest of 64%in three Pacific Outer Continental Shelf lease blocks (P-0300, P-0301 and 50%P-0306) (referred to as the “Beta Unit”), respectively, in this area.

For the year end December 31, 2017, Successor Period and Predecessor Period, our average daily productionBeta field located in federal waters approximately 11 miles offshore from the Anadarko Basin area was as follows:

Other

On April 21, 2015, we closed on the salePort of certainLong Beach, California. Our Beta Properties contained 16.7 MMBbls of ourestimated net proved oil and gas properties in Beauregard and Calcasieu Parishes, Louisiana (the “Dequincy Divestiture”), for approximately $44.0 million, before customary post-closing adjustments. We have no proved reserves in Gulf Coast (or Louisiana) as of December 31, 2017, 2016 or 2015.

During2020 based on our reserve report and generated average net production of 3.6 MBoe/d for the three months ended SeptemberDecember 31, 2020. 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.

On, June 24, 2020, the Bureau of Safety and Environmental Enforcement (“BSEE”) informed the Company that it had been approved for the Special Case Royalty Relief for the Company’s interests in the Beta Unit, effective beginning July 1, 2020. The royalty rates were reduced from 25% to 12.5% for two of the Company’s leases and from 16.67% to 8.33% for the remaining third lease. This resulted in the Company’s average net revenue interest increasing from 75.2% to 87.6%.

The Special Case Royalty Relief is subject to two key provisions related to commodity prices and capital investment. Special Case Royalty Relief will be suspended in months in which the weighted twelve-month average NYMEX oil and Henry Hub gas price exceeds $66.19 per BOE, which represents a 25% premium to the average realized price recognized by the Company during the qualification period of April 2019 to March 2020. The Special Case Royalty Relief would terminate in the event that the Company generates no benefit from the reduced rates due to the higher realized pricing for 12 consecutive months. In addition, Special Case Royalty Relief requires that during the two-year period ending June 30, 2017,2022 (and annually thereafter), the cumulative amount of a) development costs and b) incremental royalties must exceed the value of the royalty relief benefits received by the Company for production volumes at or below the calculated production volume during the qualification period. Should this condition not be met, Special Case Royalty Relief will be terminated.

East Texas / North Louisiana

Approximately 30% of our estimated proved reserves as of December 31, 2020 and approximately 39% of our average daily net production for the three months ended December 31, 2020 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 34.4 MMBoe of estimated net proved reserves as of December 31, 2020 based on our reserve report and generated average net production of 10.4 MBoe/d for the three months ended December 31, 2020.

Eagle Ford

Approximately 2% of our estimated proved reserves as of December 31, 2020 and approximately 3% of our average daily net production for the three months ended December 31, 2020 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 2.2 MMBoe of estimated net proved reserves as of December 31, 2020 based on our reserve report. Those properties collectively generated average net production of 0.8 MBoe/d for the three months ended December 31, 2020.

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. The Company maintains internal evaluations of our reserves in a secure reserve engineering database. CG&A interacts with the Company’s 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 the Company’s 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.

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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 closed onprovide CG&A 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 saleexternal 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 15 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 and Information Technology. 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 propertiesshale plays, coalbed methane fields, waterfloods and complex, faulted structures.

Mr. Brooker graduated with honors from the University of Texas at Austin in Lincoln County, Oklahoma, which had approximately 12,894 net (19,888 gross) acres for $7.0 million1989 with a Bachelor of Science degree in cash ($2.9 million, net after assumptionPetroleum Engineering and is a registered Professional Engineer in the State of liabilities), subject to standard post-closing adjustments.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.

Reserves Information

Estimated Proved Reserves

The following table sets forth ourpresents the estimated net proved reserves by product and type using SEC pricing:

(1)                                 We refer to PV-10 as the present value of estimated future net cash flows of estimated proved reserves as calculated in the respective reserves report using a discount rate of 10%. This amount includes projected revenues, estimated production costs, estimated future development costs and estimated cash flows related to future asset retirement obligations (“ARO”). PV-10 is a financial measure not defined under US GAAP. Accordingly, the following table reconciles total PV-10 to the standardized measure of discounted future net cash flows, which is the most directly comparable US GAAP financial measure. We believe the presentation of PV-10 provides useful information

because it is widely used by investors in evaluating oil and natural gas companies without regardreserves attributable to specific income tax characteristicsour properties and the standardized measure associated with the estimated proved reserves attributable to our properties as of such entities. PV-10December 31, 2020, based on the prepared reserve report by CG&A, our independent reserve engineers. The standardized measure shown in the table is not a measure of financial or operating performance under US GAAP, nor is it intended to represent the current market value of our estimated provedoil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under US GAAP.

The following table provides a reconciliation of PV-10 to the standardized measure of discounted cash flows (in thousands):

Proved Undeveloped Reserves

The following table summarizes the changes in our estimated proved undeveloped reserves during the year ended December 31, 2017 (in MBoe):

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No less than annually, we review our five-year development schedule. This review encompasses many factors, including current year drilling results, forward pricing curve, returns expectedThe data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of our drilling programestimating underground accumulations of oil and cash available during this time period, which would include cash on hand, cash generated by operations and cash from borrowings. On November 1, 2017, David Sambrooks was appointed President and Chief Executive Officernatural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the Company. Upon David’s appointment, we began a strategic reviewquality of all areas of operations. This review was completed during the fourth quarter of 2017available data and our strategy was refined to add further focus to optimizing free cash flows and keeping leverage to a minimum. As a result, in December of 2017 we decreased our current drilling activity from two drilling rigs to one drilling rig. Further, the five-year development plan was revised from a two-rig program to a one rig program. This change in strategy (reduced 5-year drilling activity) led to a reduction in our undeveloped proved inventory under SEC guidelines from 274 locations at year end 2016 to 139 locations at year end 2017. In addition, at year end 2017 our proved undeveloped type curve was revised downward by our third-party reserves engineering firm and capital costs assumptions were revised upward, both as a result of recent drilling results. The revised type curve still generates attractive capital returns of 30.6% IRR at year-end 2017 SEC pricing, and 39.1% IRR at December 31, 2017 strip pricing. As a result of our focus on optimizing free cash flow, keeping leverage to a minimum and optimizing drilling returns, all proved undeveloped reserves included in the December 31, 2017 reserve report are focused on infill drilling in the Carmen and Dacoma areas. All undeveloped locations not able to be drilled utilizing our anticipated five-year development schedule were excluded from the December 31, 2017 reserve report but continue to meet the definition of a proved undeveloped location from an engineering standpoint.

Independent Petroleum Engineers

For our Mississippian Lime and Anadarko Basin assets, our estimated reserves and related future net revenues at December 31, 2017, 2016 and 2015 are based on reports prepared by our independent third-party reserves engineering firm Cawley, Gillespie & Associates, Inc. (“CGA”), in accordance with generally accepted petroleum engineering and evaluation principlesgeological interpretation and definitions and guidelines in effect during such period as established by the SEC.

Thejudgment. Accordingly, reserve estimates shown herein formay vary from the periods indicated above have been independently evaluated by CGA, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the reserves report incorporated herein was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 30 years of practical experience in petroleum engineering, with over 28 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

Technology Used to Establish Proved Reserves

Under Rule 4-10(a)(22) of Regulation S-X, as promulgated by the SEC, proved reserves are those quantities of oil and natural gas which, by analysisthat are ultimately recovered. For a discussion of geosciencerisks associated with internal reserve estimates, see “Item 1A. Risk Factors — Risks Related to Our Business — Our estimated reserves and engineering data, can be estimated with reasonable certaintyfuture production rates are based on many assumptions that may turn out to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projectsinaccurate. Any material inaccuracies in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, CGA employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.

Internal Controls Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers, land and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to CGA in their reserves estimation process. The primary inputs to the reserves estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting records, which are subject to their own set of internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserves database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are incorporated into the reserves database as well and verified to ensure their accuracy and completeness. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserve estimates. Each quarter, estimated proved oil and gas reserves are presented to a committee of executives and key management for review and approval and annually, our development plan for proved undeveloped reserves are reviewed and approved by our executives.

At December 31, 2017, Jeromy Garcia, our General Manager — Mississippian Lime and Anadarko Basin Assets and Reserves, was primarily responsible for overseeing the preparation of our reserve estimates or underlying assumptions will materially affect the quantities and reported directly topresent value of our Chief Executive Officer. Mr. Garcia has more than 17 years of experience in the oilestimated reserves.”

Future prices received for production and gas industry. Mr. Garcia spent the first portion of his career working for El Paso Production Company — primarily working assets in the Gulf of Mexico. While at El Paso, Mr. Garcia served in multiple roles including reservoir and operational engineering. Mr. Garcia has also worked for small independents such as Whittier Energy and J&S Oil & Gas where he served as a reservoir engineer and Manager of Engineering. Mr. Garcia graduatedcosts may vary, perhaps significantly, from the Universityprices and costs assumed for purposes of Oklahoma in 2000 with a B.S degree in Petroleum Engineering and obtained his MBA fromthese estimates. The standardized measure shown above should not be construed as the Universitycurrent market value of Houston in 2009.

Production, Revenues and Price History

Oil, NGLs and natural gas are commodities. The price that we receive for the oil, NGLs and natural gas we produce is largely a function of market supply and demand. A decline in oil or natural gas prices from their current levels could have a material adverse effect on our financial position, results of operations, cash flows, quantities ofestimated oil and natural gas reserves. 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.

Development of Proved Undeveloped Reserves

As of December 31, 2020, we had 17.2 MMBoe of proved undeveloped reserves that may be economically produced and our ability to access capital markets. For additional information on these and other risks, see information set forth in “Risk Factors”.

The following table sets forth information regarding ourcomprised of 11.1 MMBbls of oil, NGLs and21.9 Bcfe of natural gas production, revenues and realized prices and production costs for2.5 MMBbls of NGLs. None of our proved undeveloped reserves (“PUDs”) as of December 31, 2020 are scheduled to be developed on a date more than five years from the yeardate the reserves were initially booked as PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2020 were due to:

Approximately 0.4% (0.1 MMBoe) of our PUDs recorded as of December 31, 2019 were developed during the twelve months ended December 31, 2017,2020. Total costs incurred to develop these PUDs were approximately $0.7 million, all of which was incurred in fiscal year 2020. In total, we incurred total capital expenditures of approximately $3.3 million during fiscal year 2020 developing PUDs, which includes $2.6 million associated with PUDs to be completed in 2021. Based on our current expectations of our cash flows, we believe that we can fund the Successor Period,drilling of our current PUD inventory and our expansions in the Predecessor Periodnext five years from our cash flow from operations and the year ended December 31, 2015.borrowings under our Revolving Credit Facility. For additional details,a more detailed discussion of our liquidity position, see information set forth in “Management’s“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.Operations — Liquidity and Capital Resources.”

Reserves sensitivity

The following table sets forth information regardingHistorically, commodity prices have been extremely volatile and due to the changes in the market with the impact of COVID-19, we expect this volatility to continue for the foreseeable future. For example, for the five years ended December 31, 2020, the NYMEX-WTI oil NGLs andfuture price ranged from a high of $76.41 per Bbl to a low of $(37.63) per Bbl, while the NYMEX-Henry Hub natural gas daily production for eachfuture price ranged from a high of the fields that represented more than 15%$4.84 per MMBtu to a low of our estimated total proved reserves for$1.48 per MMBtu. For the year ended December 31, 2017,2020, the Successor Period, the Predecessor PeriodWTI posted price ranged from a high of $63.27 per Bbl on January 6, 2020 to a low of $(37.63) per Bbl on April 20, 2020 and the NYMEX-Henry Hub market price ranged from a high of $3.35 per MMBtu on October 30, 2020 to a low of $1.48 per MMBtu on June 25, 2020. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

The following sensitivity is provided to illustrate the value of our proved developed reserves at pricing that is more representative of the current market. Our year end proved developed standardized measure at SEC pricing was $239.2 million. With an oil price of $50.00 and natural gas price of $2.70 our proved developed standardized measure would increase to $566.2 million. There is no assurance that these prices will actually be achieved.

Production, Revenue and Price History

For a description of our and Legacy Amplify’s historical 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 production costs (not including ad valorem and severance taxes) by geographic region for the years ended December 31, 2015:2020 and 2019, respectively: