UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–K

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

For the fiscal year ended December 31, 2017

OR

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

For the transition period from to .

Commission File Number: 001-35364

AMPLIFY ENERGY CORP.

(Exact name of registrant as specified in its charter)

Delaware	82-1326219
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
500 Dallas Street, Suite 1600, Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

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

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

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 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  ☑    No  ☐

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  ☑

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. Check one:

Large accelerated filer	☐	Accelerated filer	☑
Non-accelerated filer	☐  (Do not check if a smaller reporting company)	Smaller reporting company	☐
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant 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 $250.0 million on June 30, 2017, based on $10.00 per share, the last reported sales price of the shares on the OTCQX U.S. Premier marketplace 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 March 2, 2018, the registrant had 25,000,000 outstanding shares of common stock, $0.0001 par value per share.

Documents Incorporated By Reference: None

AMPLIFY ENERGY CORP.

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	9
Item 1A.	Risk Factors	30
Item 1B.	Unresolved Staff Comments	46
Item 2.	Properties	46
Item 3.	Legal Proceedings	46
Item 4.	Mine Safety Disclosures	46
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	47
Item 6.	Selected Financial Data	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	66
Item 8.	Financial Statements and Supplementary Data	68
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	68
Item 9A.	Controls and Procedures	68
Item 9B.	Other Information	71
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	72
Item 11.	Executive Compensation	76
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	88
Item 13.	Certain Relationships and Related Transactions, and Director Independence	89
Item 14.	Principal Accountant Fees and Services	91
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	92
Item 16.	Form 10-K Summary	96
Signatures		97

GLOSSARY OF OIL AND NATURAL GAS TERMS

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.

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.

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.

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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.

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.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

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.

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.

OPIS: Oil Price Information Service.

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.

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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, 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 which 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 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.

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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 United States Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the 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. Because our Predecessor was a limited partnership, it was generally not subject to federal or state income taxes and thus made no provision for federal or state income taxes in the calculation of standardized measure. 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 Form 10-K, unless we indicate otherwise:

• “Amplify Energy” and “Successor” refer to Amplify Energy Corp., the successor reporting company of Memorial Production Partners LP, individually and collectively with its subsidiaries, as the context requires;

• “Memorial Production Partners,” “MEMP,” and “Predecessor” refer to Memorial Production Partners LP, individually and collectively with its subsidiaries, as the context requires;

• “Company,” “we,” “our,” “us” or like terms refer to Memorial Production Partners for the period prior to emergence from bankruptcy and to Amplify Energy for the period after emergence from bankruptcy;

• “Predecessor’s general partner” and “MEMP GP” refer to Memorial Production Partners GP LLC, the Predecessor’s general partner and wholly owned subsidiary;

• “OLLC” refers to Amplify Energy Operating LLC, formerly known as Memorial Production Operating LLC, our wholly owned subsidiary through which we operate our properties;

• “Memorial Resource” refers to Memorial Resource Development Corp., the former owner of the Predecessor’s general partner, and its subsidiaries;

• “MRD LLC” refers to Memorial Resource Development LLC, which is the predecessor of Memorial Resource;

• “Cinco Group” refers to (i) certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies owned by: (a) Boaz Energy, LLC (“Boaz”), (b) Crown Energy Partners, LLC (“Crown”), (c) the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), (d) Propel Energy SPV LLC (“Propel SPV”), together with its wholly owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), (e) Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), (f) Tanos Energy, LLC (“Tanos”), together with its wholly owned subsidiaries and (g) Prospect Energy, LLC (“Prospect”) and (ii) certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) owned by Memorial Resource. MEMP acquired substantially all of the Cinco Group on October 1, 2013 from: (x) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which were primarily owned by two of the Funds (defined below) and (y) MRD LLC;

• “the previous owners” for accounting and financial reporting purposes refers collectively to: (a) certain oil and natural gas properties MEMP acquired from MRD LLC in April and May 2012 (“Tanos/Classic Properties”) for periods after common control commenced through their respective acquisition dates, (b) Rise Energy Operating, LLC and its wholly owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition, (c) certain oil and natural gas properties and related assets in East Texas and North Louisiana that MEMP acquired in March 2013 (the “WHT Properties”) owned by WHT Energy Partners LLC (“WHT”) from February 2, 2011 (inception) through the date of acquisition, (d) the Cinco Group and (e) certain oil and gas properties primarily located in the Joaquin Field in Shelby and Panola counties in East Texas and in Louisiana acquired from Memorial Resource in February 2015 (“Property Swap”) for periods after common control commenced through the date of acquisition;

• “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively controlled MRD Holdco LLC;

• “Finance Corp.” refers to Memorial Production Finance Corporation, our Predecessor’s wholly owned subsidiary, whose activities were limited to co-issuing our Predecessor’s debt securities and engaging in other activities incidental thereto, which was dissolved following the effective date of the Plan (as defined in Note 2 of the Notes to the Consolidated and Combined Financial Statements under “Item 8. Financial Statements and Supplementary Data”);

• “MRD Holdco” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource; and

• “NGP” refers to Natural Gas Partners.

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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, which may include statements about our:

• business strategies;

• acquisition and disposition strategy;

• cash flows and liquidity;

• financial strategy;

• ability to replace the reserves we produce through drilling;

• drilling locations;

• oil and natural gas reserves;

• technology;

• realized oil, natural gas and NGL prices;

• production volumes;

• lease operating expense;

• gathering, processing and transportation;

• general and administrative expense;

• future operating results;

• ability to procure drilling and production equipment;

• ability to procure oil field labor;

• planned capital expenditures and the availability of capital resources to fund capital expenditures;

• ability to access capital markets;

• marketing of oil, natural gas and NGLs;

• acts of God, fires, earthquakes, storms, floods, other adverse weather conditions, war, acts of terrorism, military operations or national emergency;

• expectations regarding general economic conditions;

• impact of the Tax Cuts and Jobs Act of 2017;

• competition in the oil and natural gas industry;

• effectiveness of risk management activities;

• environmental liabilities;

• counterparty credit risk;

• expectations regarding governmental regulation and taxation;

• expectations regarding developments in oil-producing and natural-gas producing countries; and

• plans, objectives, expectations and intentions.

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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 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:

• our results of evaluation and implementation of strategic alternatives;

• our inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing, or otherwise;

• our indebtedness and our ability to satisfy our debt obligations and a potential inability to effect deleveraging transactions or otherwise reduce those risks;

• risks related to a redetermination of the borrowing base under our senior secured reserve-based revolving credit facility;

• our ability to access funds on acceptable terms, if at all, because of the terms and conditions governing our indebtedness;

• volatility in the prices for oil, natural gas and NGLs, including further or sustained declines in commodity prices;

• the potential for additional impairments due to continuing or future declines in oil, natural gas and NGL prices;

• the uncertainty inherent in estimating quantities of oil, natural gas and NGLs reserves;

• our substantial future capital requirements, which may be subject to limited availability of financing;

• the uncertainty inherent in the development and production of oil and natural gas;

• our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base;

• the existence of unanticipated liabilities or problems relating to acquired or divested businesses or properties;

• potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties;

• the consequences of changes we have made, or may make from time to time in the future, to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity;

• potential shortages of, or increased costs for, drilling and production equipment and supply materials for production, such as CO₂;

• potential difficulties in the marketing of oil and natural gas;

• changes to the financial condition of counterparties;

• uncertainties surrounding the success of our secondary and tertiary recovery efforts;

• competition in the oil and natural gas industry;

• general political and economic conditions, globally and in the jurisdictions in which we operate;

• the impact of legislation and governmental regulations, including those related to climate change and hydraulic fracturing;

• the risk that our hedging strategy may be ineffective or may reduce our income;

• the cost and availability of insurance as well as operating risks that may not be covered by an effective indemnity or insurance;

• actions of third-party co-owners of interest in properties in which we also own an interest; and

• other risks and uncertainties described in “Item 1A. Risk Factors.”

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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 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 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 our behalf.

8

PART I

ITEM 1. BUSINESS

References

When referring to Amplify Energy Corp. (also referred to as “Successor,” “Amplify Energy,” or the “Company”), the intent is to refer to Amplify Energy, a Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Amplify Energy is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

Overview

Amplify Energy is an independent oil and natural gas company that was formed on March 21, 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from December 2011 to May 2017. As discussed further in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data”, on January 16, 2017 (the “Petition Date”), MEMP and certain of its subsidiaries (collectively with MEMP, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262). During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective May 4, 2017 (the “Effective Date”).

We operate in one reportable segment 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 and are located in Texas, Louisiana, Wyoming and offshore Southern California. 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, 2017:

• Our total estimated proved reserves were approximately 989.7 Bcfe, of which approximately 44% were oil and 71% were classified as proved developed reserves;

• We produced from 2,547 gross (1,498 net) producing wells across our properties, with an average working interest of 59% and the Company is the operator of record of the properties containing 93% of our total estimated proved reserves; and

• Our average net production for the three months ended December 31, 2017 was 184.3 MMcfe/d, implying a reserve-to-production ratio of approximately 15 years.

Recent Developments

Emergence from Voluntary Reorganization under Chapter 11

On April 14, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) approving the Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (as amended and supplemented, the “Plan”).

On the Effective Date, the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and the Company emerged from bankruptcy. Although the Company is no longer a debtor in possession, the Company was a debtor in possession from January 16, 2017 through May 4, 2017. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.

Upon emergence from the Chapter 11 proceedings on May 4, 2017, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims.

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In accordance with the Plan, on the Effective Date:

• The Successor issued (i) 25,000,000 new shares (the “New Common Shares”) of its common stock, par value $0.0001 per share (“common stock”); and (ii) warrants (the “Warrants”) to purchase up to 2,173,913 shares of the Company’s common stock exercisable for a five-year period commencing on the Effective Date entitling holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding common shares (including common shares as of the Effective Date issuable upon full exercise of the Warrants, but excluding any common shares issuable under the Management Incentive Plan (the “MIP”)), at a per share exercise price of $42.60.

• The holders of claims under the Predecessor’s revolving credit facility received a full recovery, consisting of a cash pay down and their pro rata share of the $1 billion exit senior secured reserve-based revolving credit facility (the “Credit Facility”), as further discussed in Note 10of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for additional information.

• The 7.625% senior notes due May 2021 (“2021 Senior Notes”) and 6.875% senior notes due August 2022 (“2022 Senior Notes” and collectively, the “Notes”) were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received (directly or indirectly) their pro rata share of New Common Shares representing, in the aggregate, 98% of the New Common Shares on the Effective Date (subject to dilution by the MIP and the common shares issuable upon exercise of the Warrants). Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution.

• The Predecessor’s common units were cancelled, and each common unitholder received its pro rata share of: (i) 2% of the New Common Shares, (ii) the Warrants, and (iii) cash in an aggregate amount of approximately $1.3 million.

• The holders of administrative expense claims, priority tax claims, other priority claims and general unsecured creditors of the Predecessor received in exchange for their claims payment in full in cash or otherwise had their rights unimpaired under Title 11 of the United States Code.

• The Successor entered into a stockholders agreement with certain parties pursuant to which the Successor agreed to, at the direction of such stockholders, use commercially reasonable efforts to effect the sale of their common stock.

• The Successor entered into a registration rights agreement with certain parties pursuant to which the Successor agreed to, among other things, file a registration statement with the SEC within 90 days of the receipt of a request from the stockholders party thereto covering the offer and resale of the common stock held by such stockholders.

• The Company’s MIP became effective, such that an aggregate of 2,322,404 shares of the Company’s common stock became available for grant pursuant to awards under the MIP.

• The term of the Predecessor’s general partner’s board of directors automatically expired on the Effective Date. The Successor formed a new seven-member board of directors consisting of the President and Chief Executive Officer, one director of the Predecessor, and five new members designated by certain parties to the plan support agreement.

Properties

We engaged Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2017. The following table summarizes information, based on a reserve report prepared by our internal reserve engineers and audited by Ryder Scott (which we refer to as our “reserve report”), about our proved oil and natural gas reserves by geographic region as of December 31, 2017 and our average net production for the three months ended December 31, 2017:

	Estimated Net Proved Reserves							Average Net Production			Average		Producing Wells
											Reserve
			% Oil and	% Natural	% Proved	Standardized				% of	-to-Production
Region	Bcfe (1)		NGL	Gas	Developed	Measure (2)		MMcfe/d		Total	Ratio (3)		Gross		Net
						(in millions)					(Years)
East Texas/Louisiana		460	25%	75%	69%	$	298		106.3	58%		11.9		1,616		905
Rockies		264	100%	0%	73%		142		27.0	15%		26.8		116		116
California		177	100%	0%	65%		254		25.4	13%		19.1		58		58
South Texas		89	32%	68%	90%		74		25.6	14%		9.5		757		419
Total		990	59%	41%	71%	$	768		184.3	100%		14.7		2,547		1,498

(1) Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2) Standardized measure is calculated in accordance with Accounting Standards Codification, or ASC, Topic 932, Extractive Activities—Oil and Gas, and is calculated using SEC pricing, before market differentials, of $51.34/Bbl for crude oil and NGLs and $2.98/MMBtu for natural gas.

(3) The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of December 31, 2017 by the annualized average net production for the three months ended December 31, 2017.

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Our Areas of Operation

East Texas/Louisiana

Approximately 47% of our estimated proved reserves as of December 31, 2017 and approximately 58% of our average daily net production for the three months ended December 31, 2017 were located in the East Texas/Louisiana region. Our East Texas/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 460.3 Bcfe of estimated net proved reserves as of December 31, 2017 based on our reserve report and generated average net production of 106.3 MMcfe/d for the three months ended December 31, 2017. In October 2017, we launched a divestiture process for our assets in the East Texas/Louisiana region.

Rockies

Approximately 27% of our estimated proved reserves as of December 31, 2017 and approximately 15.0% of our average daily net production for the three months ended December 31, 2017 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 44.0 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2017 based on our reserve report and generated average net production of 27.0 MMcfe/d for the three months ended December 31, 2017. In October 2017, we launched a divestiture process for our assets in the Rockies region.

California

Approximately 18% of our estimated proved reserves as of December 31, 2017 and approximately 13% of our average daily net production for the three months ended December 31, 2017 were located offshore Southern California. These properties (the “Beta properties”) consist of: 100% of the working interests and currently an 87.6% 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 located in federal waters approximately 11 miles offshore the Port of Long Beach, California. Our Beta properties contained 29.4 MMBbls of estimated net proved oil reserves as of December 31, 2017 based on our reserve report. Oil and gas is 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 systems. 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.

Based on our reserve report, the Beta field contains more than 15% of our total estimated reserves. The following table summarizes production volumes from this field for the periods presented:

	Period from		Period from
	May 5, 2017		January 1, 2017		For the Year Ended
	through		through		December 31,
	December 31, 2017		May 4, 2017		2016		2015
Production Volumes:
Oil (MBbls)		1,022		486		1,445		860
Average net production (MBbls/d)		4.2		3.9		3.9		2.4

The increase in the production volumes between 2015 and the subsequent periods is primarily due to the acquisition of the remaining interests in our Beta properties from a third party.

Due to low oil and gas prices, the Beta leases were all granted royalty relief by the U.S. Department of Interior in July 2016. On our two primary producing leases, the royalty rate was reduced from 25% to 12.5%, and on our third lease, the royalty rate was reduced from 16.67% to 8.33%, for a weighted average of 12.4% overall. The royalty relief rates will apply to all hydrocarbon production up to 165,801 Boe per month. Monthly production above that level and up to 331,602 Boe per month will bear royalties at 1.5 times the original effective royalty rate. For monthly production above 331,602 Boe per month, the royalty rate will return to the original effective royalty rates. The royalty relief rates will also be suspended in months in which the trailing twelve-month weighted average NYMEX oil and Henry Hub gas price exceeds $55.16 per Boe which represents a 25% premium to the average realized price recognized by the Company during the qualification period. The royalty relief would end in the event that the Company generates no benefit from the royalty relief rates due to either higher production or realized pricing for 12 consecutive months.

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South Texas

Approximately 9% of our estimated proved reserves as of December 31, 2016 and approximately 14% of our average daily net production for the three months ended December 31, 2017 were located in the South Texas region. Our South Texas properties include wells and properties in numerous fields located primarily in the Eagle Ford, Eagleville, NE Thompsonville, Laredo and East Seven Sisters fields. Our South Texas properties contained 88.6 Bcfe of estimated net proved reserves as of December 31, 2017 based on our reserve report. Those properties collectively generated average net production of 25.6 MMcfe/d for the three months ended December 31, 2017. In July 2017, we launched a divestiture process for our assets in the South Texas region.

Our Oil and Natural Gas Data

Our Reserves

Internal Controls. Our proved reserves were estimated at the well or unit level and audited for reporting purposes by Ryder Scott, our independent reserve engineers. The Company maintains internal evaluations of our reserves in a secure reserve engineering database. Ryder Scott 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 for the reserves audit process. 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 Credit Facility. Our reserve estimates are audited by Ryder Scott at least annually.

Our internal professional staff works closely with Ryder Scott to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve audit process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide Ryder Scott 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 audit of our reserves.

Qualifications of Responsible Technical Persons

Internal Engineers. Christa Yin is the technical person at the Company primarily responsible for overseeing the preparation of the reserves estimates and liasoning with and providing oversight of our third-party reserve engineers, which audited the internally prepared reserve report for our properties. Ms. Yin has been practicing petroleum engineering at the Company since March 2015 and has over 19 years of experience in the estimation and evaluation of reserves. From March 2014 to March 2015, she was employed by Tundra Oil and Gas, where she was responsible for analysis of acquisitions, generating development plans and managing reserves. From August 2011 to March 2014, she worked for HighMount Exploration & Production LLC as Manager of Acquisitions and Divestitures. From February 2005 to August 2011, Ms. Yin was employed by Tecpetrol, where she was responsible for generating development plans and managing and evaluating the reserves for the Gulf Coast region. From November 2003 to February 2005, Ms. Yin was employed by Marathon Oil Company where she was responsible for evaluating reserves and field development of various fields in Oklahoma. From June 1997 to November 2003, she held various positions which included the evaluation and estimation of reserves at Coastal Oil & Gas, which subsequently merged with El Paso Production Company. Ms. Yin is a graduate of Texas A&M University and holds a B.S. in petroleum engineering.

Ryder Scott Company, L.P. Ryder Scott is an independent oil and natural gas consulting firm. No director, officer, or key employee of Ryder Scott has any financial ownership in us or any of our affiliates. Ryder Scott’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported. Ryder Scott has not performed other work for us or any of our affiliates that would affect its objectivity. The audit of estimates of our proved reserves presented in the Ryder Scott reserve report were overseen by Timothy Wayne Smith.

Mr. Smith has been practicing consulting petroleum engineering at Ryder Scott since 2008. Before joining Ryder Scott, Mr. Smith served in a number of engineering positions with Wintershall Energy and Cities Service Oil Company. Mr. Smith is a Licensed Professional Engineer in the State of Texas with over 25 years of practical experience in the estimation and evaluation of petroleum reserves. He graduated from West Virginia University with a B.S. in petroleum engineering and from University of Phoenix with an M.B.A.

Mr. Smith 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 applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

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Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure associated with the estimated proved reserves attributable to our properties as of December 31, 2017, based on our internally prepared reserve report audited by Ryder Scott, our independent reserve engineers. The standardized measure shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.

	Reserves
	Oil		Natural Gas		NGLs		Total
	(MBbls)		(MMcf)		(MBbls)		(MMcfe) (1)
Estimated Proved Reserves
Developed		50,014		299,481		17,982		707,459
Undeveloped		21,990		107,077		7,207		282,262
Total		72,004		406,558		25,189		989,721
Proved developed reserves as a percentage of total proved reserves								71	%
Standardized measure (in thousands) (2)							$	767,671
Oil and Natural Gas Prices (3)
Oil – WTI per Bbl							$	51.34
Natural gas – Henry Hub per MMBtu							$	2.98

(1) Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2) Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest expense, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions. For a description of our commodity derivative contracts, see “Item 1. Business—Operations—Derivative Activities” as well as “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commodity Derivative Contracts.”

(3) Our estimated net proved reserves and related standardized measure were determined using 12-month trailing average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month in effect as of the date of the estimate, without giving effect to derivative contracts, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

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. For a discussion of risks associated with internal reserve estimates, see “Item 1A. Risk Factors — Risks Related to Our Business — Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure shown above should not be construed as the current market value of our estimated 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, 2017, we had 282.3 Bcfe of proved undeveloped reserves comprised of 22.0 MMBbls of oil, 107.1 Bcfe of natural gas and 7 MMBbls of NGLs. None of our PUDs as of December 31, 2017 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.

Changes in PUDs that occurred during 2017 were due to:

• Upward performance and price revisions of 46 Bcfe;

• Reclassifications of 20 Bcfe into proved developed reserves as wells are drilled, completed and turned to production; and

• Reserve additions of 6 Bcfe.

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Approximately 8% (20 Bcfe) of our PUDs recorded as of December 31, 2016 were developed during the twelve months ended December 31, 2017. Total costs incurred to develop these PUDs were approximately $30.5 million, of which $0.8 million was incurred in fiscal year 2016 and $29.7 million was incurred in fiscal year 2017. In total, we incurred total capital expenditures of approximately $41.5 million during fiscal year 2017 developing PUDs, which includes $11.7 million associated with PUDs to be completed in 2018. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in the upcoming years. 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 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 and the previous owners’ combined 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.”

The following tables summarize our average net production, average unhedged sales prices by product and average production costs by geographic region for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015, respectively:

	For the Period from May 5, 2017 through December 31, 2017 (Successor)
	Oil				NGLs				Natural Gas				Total
			Average				Average				Average				Average		Lease
	Production		Sales		Production		Sales		Production		Sales		Production		Sales		Operating
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price		Expense
	(MBbls)		($/bbl)		(MBbls)		($/bbl)		(MMcf)		($/Mcf)		(MMcfe)		($/Mcfe)		($/Mcfe)
East Texas/Louisiana		163	$	50.31		811	$	22.40		18,402	$	3.06		24,240	$	3.41	$	0.65
Rockies		879		45.52		151		34.77		—		—		6,180		7.32		4.95
South Texas		316		50.88		152		22.37		3,483		2.84		6,297		4.67		1.17
California		1,022		46.81		—		—		—		—		6,133		7.80		3.38
Total		2,380	$	47.11		1,114	$	24.07		21,885	$	3.03		42,850	$	4.79	$	1.74
Average net production (MMcfe/d)														177.8

	For the period from January 1, 2017 through May 4, 2017 (Predecessor)
	Oil				NGLs				Natural Gas				Total
			Average				Average				Average				Average		Lease
	Production		Sales		Production		Sales		Production		Sales		Production		Sales		Operating
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price		Expense
	(MBbls)		($/bbl)		(MBbls)		($/bbl)		(MMcf)		($/Mcf)		(MMcfe)		($/Mcfe)		($/Mcfe)
East Texas/Louisiana		149	$	48.23		456	$	20.68		10,708	$	3.17		14,345	$	3.53	$	0.54
Rockies		440		46.34		86		37.10		—		—		3,155		7.48		5.04
South Texas		129		49.48		74		20.05		1,703		3.02		2,919		4.46		1.18
California		486		44.77		—		—		—		—		2,917		7.46		2.88
Total		1,204	$	46.28		616	$	22.90		12,411	$	3.15		23,336	$	4.67	$	1.52
Average net production (MMcfe/d)														188.2

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	For the Year Ended December 31, 2016 (Predecessor)
	Oil				NGLs				Natural Gas				Total
			Average				Average				Average				Average		Lease
	Production		Sales		Production		Sales		Production		Sales		Production		Sales		Operating
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price		Expense
	(MBbls)		($/bbl)		(MBbls)		($/bbl)		(MMcf)		($/Mcf)		(MMcfe)		($/Mcfe)		($/Mcfe)
East Texas/Louisiana		443	$	39.48		1,841	$	13.64		37,236	$	2.45		50,938	$	2.62	$	0.53
Rockies		1,399		37.94		202		22.02		1,612		1.73		11,217		5.38		4.45
South Texas		416		39.24		240		14.95		5,804		2.29		9,742		3.41		1.31
California		1,445		34.97		—		—		—		—		8,672		5.83		3.62
Permian		180		33.39		—		—		124		2.54		1,204		5.25		4.10
Total		3,883	$	36.94		2,283	$	14.52		44,776	$	2.40		81,773	$	3.47	$	1.54
Average net production (MMcfe/d)														223.4

	For the Year Ended December 31, 2015 (Predecessor)
	Oil				NGLs				Natural Gas				Total
			Average				Average				Average				Average		Lease
	Production		Sales		Production		Sales		Production		Sales		Production		Sales		Operating
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price		Expense
	(MBbls)		($/bbl)		(MBbls)		($/bbl)		(MMcf)		($/Mcf)		(MMcfe)		($/Mcfe)		($/Mcfe)
East Texas/Louisiana		538	$	43.93		2,192	$	13.79		40,313	$	2.68		56,694	$	2.86	$	0.78
Rockies		1,657		43.44		366		24.01		3,486		2.48		15,622		5.72		3.54
South Texas		460		45.00		262		15.59		6,596		2.54		10,929		3.80		1.59
California		860		41.21		—		—		—		—		5,159		6.87		4.45
Permian		572		45.37		—		—		480		2.51		3,911		6.94		7.29
Total		4,087	$	43.48		2,820	$	15.28		50,875	$	2.65		92,315	$	3.85	$	1.82
Average net production (MMcfe/d)														252.9

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, 2017.

	Oil				Natural Gas
	Gross		Net		Gross		Net
Operated		197		191		1,449		1,209
Non-operated		273		24		628		75
Total		470		215		2,077		1,284

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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, 2017, substantially all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2017 relating to our leasehold acreage.

Region	Developed Acreage (1)
	Gross (2)		Net (3)
East Texas/Louisiana		220,805		128,221
Rockies		6,573		6,573
South Texas		109,185		85,297
California		17,280		17,280
Total		353,843		237,371

(1) Developed acres are acres spaced or assigned to productive wells or wells capable of production.

(2) A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(3) A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Undeveloped Acreage

The following table sets forth information as of December 31, 2017 relating to our undeveloped leasehold acreage (including the remaining terms of leases and concessions).

	Undeveloped				Net Acreage Subject to
Region	Acreage				Lease Expiration by Year
	Gross (1)		Net (2)		2018		2019		2020
East Texas/Louisiana		30,636		17,830		544		37		810
Rockies		120		120		—		—		—
South Texas		6,346		6,346		4,415		—		—
Total		37,102		24,296		4,959		37		810

(1) A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(2) A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Drilling Activities

Our drilling activities primarily consist of development wells. The following table sets forth information with respect to wells drilled and completed by us or the previous owners 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, 2017, 13 gross (3.6 net) wells were in various stages of completion.

	Year Ended December 31,
	2017				2016				2015
	Gross		Net		Gross		Net		Gross		Net
Development wells:
Productive		25.0		4.4		23.0		8.0		43.0		20.0
Dry		—		—		—		—		—		—
Exploratory wells:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		1.0		1.0
Total wells:
Productive		25.0		4.4		23.0		8.0		43.0		20.0
Dry		—		—		—		—		1.0		1.0
Total		25.0		4.4		23.0		8.0		44.0		21.0

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.

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We have entered into a long-term gas gathering agreement associated with a certain portion of our East Texas production with a third party midstream service provider that has volumetric requirements. Information regarding our delivery commitments under this contract is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations” and Note 15 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data,” both contained herein.

Operations

General

As of December 31, 2017, the Company is the operator of record of properties containing 93% 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:

	Successor	Predecessor
	Period from	Period from
	May 5, 2017	January 1, 2017
	through	through	For the Year Ending December 31,
	December 31, 2017	May 4, 2017	2016	2015
Major customers:
Phillips 66	23%	19%	19%	12%
Sinclair Oil & Gas Company	19%	20%	16%	18%
CIMA Energy	11%	n/a	n/a	n/a
BP America Production Company	10%	10%	n/a	n/a
Royal Dutch Shell plc and subsidiaries	n/a	n/a	14%	14%

The production sales agreements covering our properties contain customary terms and conditions for the oil and natural gas industry and provide for sales based on prevailing market prices. A majority of those agreements have terms that renew on a month-to-month basis until either party gives advance written notice of termination.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of a portion of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether and we were unable to replace them, the loss of any such customer could have a detrimental effect on our production volumes and revenues in general.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. More thorough title investigations are customarily made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under natural gas leases, or net profits interests.

Derivative Activities

We enter into commodity derivative contracts with unaffiliated third parties, generally lenders under our Credit Facility or their affiliates, to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. Our outstanding commodity derivative contracts currently consist of floating-for-fixed swaps. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 75% of our estimated production from total proved developed producing reserves over a one-to-three year period at any given point of time to satisfy the hedging covenants in our Credit Facility and pursuant to our internal policies. We may, however, from time to time, hedge more or less than this approximate amount.

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those in our revolving credit facility) to fixed interest rates.

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It is our policy to enter into derivative contracts only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our Credit Facility are counterparties to our derivative contracts. We will continue to evaluate the benefit of employing derivatives in the future. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information.

Competition

We operate in a highly competitive environment for acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us.

Seasonal Nature of Business

The price we receive for our natural gas production is impacted by seasonal fluctuations in demand for natural gas. The demand for natural gas typically peaks during the coldest months and tapers off during the milder months, with a slight increase during the summer to meet the demands of electric generators. The weather during any particular season can affect this cyclical demand for natural gas. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Hydraulic Fracturing

We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete, except in our offshore wells. Hydraulic fracturing is a necessary part of the completion process because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. Our proved non-producing and proved undeveloped reserves make up 36% of the proved reserves with approximately 68% of these requiring hydraulic fracturing as of December 31, 2017.

We have and continue to follow applicable industry standard practices and legal and regulatory requirements for groundwater protection in our operations which are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design essentially eliminates a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abnormal change occurred to the injection pressure or annular pressure.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements.

Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it in a way that minimizes the impact to nearby surface water by disposing into approved disposal or injection wells. We currently do not discharge water to the surface.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, see “—Environmental, Occupational Health and Safety Matters and Regulations—Hydraulic Fracturing.”

Insurance

In accordance with customary industry practice, we maintain insurance against many potential operational risks and losses that could be covered by the following policies:

•     Commercial General Liability;	•     Oil Pollution Act Liability;
•     Primary Umbrella / Excess Liability;	•     Pollution Legal Liability;
•     Property;	•     Charterer’s Legal Liability;
•     Workers’ Compensation;	•     Non-Owned Aircraft Liability;
•     Employer’s Liability;	•     Automobile Liability;
•     Maritime Employer’s Liability;	•     Directors & Officers Liability;

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•     U.S. Longshore and Harbor Workers’;	•     Employment Practices Liability;
•     Energy Package/Control of Well;	•     Crime; and
•     Loss of Production Income (offshore only);	•     Fiduciary.

Onshore and Offshore Insurance Program. We maintain insurance coverage against potential losses that we believe is customary in the industry. As of December 31, 2017, we maintain commercial general liability insurance, automobile liability insurance and umbrella/excess liability insurance. Our commercial general liability insurance has limits of $1.0 million per occurrence/$2.0 million in the aggregate and a $100,000 self-insured retention (except $250,000 with respect to Pollution Clean Up Costs). Our general liability insurance covers us for, among other things, legal and contractual liabilities arising out of third party property damage and bodily injury and for sudden and accidental pollution liability. Our automobile liability insurance has limits of $1.0 million per occurrence. Our umbrella/excess liability limits for each occurrence is a minimum of $25.0 million. There is no deductible on our umbrella/excess liability insurance. Our umbrella/excess liability insurance is in addition to our general and automobile liability policy and may be triggered if the general or automobile liability insurance policy limits are exceeded and exhausted. In addition, we maintain an energy package policy that includes control of well coverage (“COW”) with per occurrence limits for COW ranging from $10.0 million to $100.0 million and retentions ranging from $100,000 to $500,000, with an additional annual aggregate retention of $1.0 million. Specific to offshore operations, the energy package policy also includes loss of production income coverage insuring us against a loss up to $52.65 million due to a temporary interruption in the oil supply from our offshore facilities as a result of an insured physical loss to our offshore facilities. Our control of well policy insures us for blowout risks associated with drilling, completing and operating our wells. We maintain two separate Pollution Legal Liability (“PLL”) policies, one for all U.S. onshore operations, excluding California and one for California only. Our PLL non-California insurance policy has limits of $10.0 million per pollution event with a $1.0 million retention. Our PLL California-only insurance policy has limits of $10.0 million with a $250,000 retention.

As of December 31, 2017, we have insurance policies in effect that are intended to provide coverage for pollution losses including those related to our hydraulic fracturing operations. These policies may not cover fines, penalties or costs and expenses related to government-mandated clean-up of pollution. In addition, these policies do not provide coverage for all liabilities. Our insurance coverage may not be adequate to cover claims that may arise and we may be unable to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We enter into master services agreements (“MSAs”) with various service providers. These MSAs allocate potential liabilities and risks between the parties. Under certain MSAs, we indemnify certain service providers, including hydraulic fracturing service providers, for pollution and contamination of any kind, damages to or losses from wells or underground formations and damages to property, including pipelines, storage or production facilities. Under certain other MSAs, the service providers indemnify us for pollution or contamination that originates above the surface and is caused by the service provider’s equipment or services, unless such pollution or contamination is caused by our gross negligence or willful misconduct and we indemnify the service providers for all other pollution or contamination that may occur during operations (including that which may result from seepage or any other uncontrolled flow of oil, natural gas or other fluids from the well), unless such pollution or contamination is caused by the service provider’s gross negligence or willful misconduct. Generally, we also agree to indemnify the service providers against claims arising from our employees’ bodily injury or death to the extent that our employees are injured by or during service operations, unless resulting from the service provider’s gross negligence or willful misconduct. Similarly, the service providers generally agree to indemnify us for liabilities arising from bodily injury to or death of any of their employees, unless resulting from our gross negligence or willful misconduct. In addition, the service providers generally agree to indemnify us for loss or destruction of property or equipment that they own, unless resulting from our gross negligence or willful misconduct. In turn, we generally agree to indemnify the service providers for loss or destruction of property or equipment we own, unless resulting from the service provider’s gross negligence or willful misconduct.

Despite the general allocation of risk discussed above, we may not succeed in enforcing such contractual allocation of risk, we may be required to enter into a MSA with terms that vary from such allocation of risk and may incur costs or liabilities that fall outside any contractual allocation of risk. As a result, we may incur substantial losses that could materially and adversely affect our financial position, results of operations and cash flows.

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Environmental, Occupational Health and Safety Matters and Regulations

General

Our oil and natural gas development and production operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and in some instances, the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

The following is a summary of the more significant existing environmental, occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

BOEM & BSEE

Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters. The Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) have broad authority to regulate our oil and gas operations associated with our Beta properties.

BOEM is responsible for managing environmentally and economically responsible development of the nation’s offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the EPA, U.S. Department of Transportation and the South Coast Air Quality Management District. BOEM generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. In July 2016, BOEM issued updated guidance for determining if and when additional security is required for Outer Continental Shelf (“OCS”) leases, pipeline rights-of-way and rights-of-use and easement. The new criteria may require lessees or operators to take additional steps to demonstrate that they have the financial ability to carry out their obligations. In June 2017, BOEM announced that the implementation timeline would be extended, except in circumstances where there is a substantial risk of nonperformance of the interest holder’s obligations.

BSEE is responsible for safety and environmental oversight of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. BSEE regulations require offshore production facilities and pipelines located on the OCS to meet stringent engineering and construction specifications, and BSEE has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas, prohibit the flaring of liquid hydrocarbons and govern the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities.

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BOEM and BSEE have adopted regulations providing for enforcement actions, including civil penalties and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta properties be suspended or terminated and we may be subject to civil or criminal liability.

In January 2016, BOEM and BSEE entered into a settlement agreement with environmental groups promising to study the potential environmental impacts of well-stimulation practices on the Pacific OCS, including hydraulic fracturing and acid well stimulation. The study was completed in May 2016, finding no significant impact from these activities. While BSEE has resumed its review of permit applications involving hydraulic fracturing operations or acid well stimulation on the Pacific OCS, the State of California and environmental groups filed lawsuits in December 2016 challenging the environmental study, which, if successful, could delay or restrict the issuance of permits involving hydraulic fracturing and/or acid well stimulation. Although we do not use either hydraulic fracturing or acid stimulation routinely, delays in the approval or refusal of plans and issuance of permits by BOEM or BSEE because of staffing, economic, environmental or other reasons (or other actions taken by BOEM or BSEE) could adversely affect our offshore operations. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations.

Hazardous Substances and Waste Handling

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, referred to as CERCLA or the Superfund law and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed “responsible parties.” These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file common law-based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Also, comparable state statutes may not contain a similar exemption for petroleum. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

The Oil Pollution Act of 1990 (“OPA”) is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills. For example, the California Department of Fish and Game's Office of Oil Spill Prevention and Response have adopted oil-spill prevention regulations that overlap with federal regulations.

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We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. These wastes, instead, are regulated under RCRA's less stringent solid waste provisions, state laws or other federal laws. It is possible that these wastes, which could include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA entered into a consent decree requiring it to review its regulation of oil and gas waste. The consent decree requires the EPA to determine whether any revisions are necessary by March 2019. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

It is possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials (“NORM”). NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with the requirements of CERCLA, RCRA, OPA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Water Discharges and Other Waste Discharges & Spills

The Federal Water Pollution Control Act (also known as the Clean Water Act), the Safe Drinking Water Act (“SDWA”), the OPA and analogous state laws, impose restrictions and strict controls with respect to the unauthorized discharge of pollutants, including oil and hazardous substances, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). In June 2015, the EPA and the Corps issued a rule to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs. In October 2015, the U.S. Court of Appeals for the Sixth Circuit stayed the rule revising the WOTUS definition nationwide pending further action of the court. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” However, in January 2018, the U.S. Supreme Court ruled that the rule revising the WOTUS definition must first be reviewed in the federal district courts, which could result in a withdrawal of the stay by the Sixth Circuit. In addition, the EPA has proposed to repeal the rule revising the WOTUS definition, and in January 2018 the EPA released a final rule that delays implementation of the rule revising the WOTUS definition until 2020 to allow time for EPA to reconsider the definition of the term “waters of the United States.” Several states and environmental groups have since filed lawsuits challenging the delay rule. To the extent the rule revising the definition of WOTUS is implemented, it could significantly expand federal control of land and water resources across the United States and lead to substantial additional permitting and regulatory requirements.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential to delay the development of natural gas and oil projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development and require us to incur compliance costs.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure (“SPCC”) plans, in connection with on-site storage of significant quantities of oil. We maintain all required discharge permits necessary to conduct our operations and we believe we are in substantial compliance with their terms.

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Hydraulic Fracturing

We use hydraulic fracturing extensively in our onshore operations, but not our offshore operations. Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the SDWA involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. In addition, the EPA plans to develop a Notice of Proposed Rulemaking, which would describe a proposed mechanism – regulatory, voluntary, or a combination of both – to collect data on hydraulic fracturing chemical substances and mixtures under the Toxic Substances Control Act (“TSCA”). Also, in June 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants; for certain facilities, compliance is required by August 2018. The EPA is also conducting a study of private wastewater treatment facilities, also known as centralized waste treatment (“CWT”) facilities, accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

Further, in August 2012, the EPA published final rules that subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the new source performance standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The rules include NSPS for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rules seek to achieve a 95% reduction in volatile organic compounds (“VOCs”) emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules could require a number of modifications to our operations including the installation of new equipment. In May 2016, the EPA amended its regulations to impose new standards for methane and VOC emissions for certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector. Although these standards currently remain in effect, EPA proposed in June 2017 to stay certain requirements for two years while it reconsiders the entirety of the standards. The EPA also finalized a plan in May 2016 to implement its minor new source review program on Indian lands for oil and natural gas production. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs and could adversely impact our business.

In addition, in March 2015, the Bureau of Land Management (“BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures and the depths of all usable water. Following years of litigation, the BLM rescinded the rule in December 2017. However, the State of California and environmental groups filed lawsuits in January 2018 challenging BLM’s rescission of the rule. Also, in November 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks and replace outdated equipment that vents large quantities of gas into the air. The rule also clarified when operators owe the government royalties for flared gas. In December 2017, BLM suspended certain requirements of the rule until 2019. However, the States of California and New Mexico and environmental groups filed lawsuits in December 2017 challenging BLM’s suspension of the rule.

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Several states have also adopted, or are considering adopting, regulations requiring the disclosure of the chemicals used in hydraulic fracturing and/or otherwise impose additional requirements for hydraulic fracturing activities. For example, in October 2011, the Louisiana Department of Natural Resources adopted rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. Also, Texas requires oil and natural gas operators to disclose to the Railroad Commission of Texas (“Commission”) and the public the chemicals used in the hydraulic fracturing process, as well as the total volume of water used. Also, in May 2013, the Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The “well integrity rule” took effect in January 2014. Additionally, in October 2014, the Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments, which became effective in November 2014, also clarify the Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Commission has used this authority to deny permits for waste disposal wells. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Certain governmental reviews have been conducted that focus on environmental aspects of hydraulic fracturing practices, which could lead to increased regulation. For example, in December 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, in February 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated various other aspects of hydraulic fracturing. In addition, as discussed above, BOEM and BSEE completed a study in May 2016 regarding the potential environmental impacts of well-stimulation practices on the Pacific OCS. These studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

A number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have induced seismic activity and adversely impacted drinking water supplies, use of surface water, and the environment generally. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. In the event state or local legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. For example, the U.S. Congress has from time to time considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

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Air Emissions

The federal Clean Air Act, as amended (“CAA”), and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in August 2012, the EPA published final regulations under the CAA that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail above under the caption “Hydraulic Fracturing.” In May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. In addition, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion in October 2015 and has announced that it intends to complete most initial area designations under the standard by April 2018. State implementation of the revised NAAQS could result in stricter permitting requirements or delay and increased expenditures for air pollution control equipment.

The South Coast Air Quality Management District (“SCAQMD”) is a regulatory subdivision of the State of California and responsible for air pollution control from stationary sources within Orange County and designated portions of Los Angeles, Riverside, and San Bernardino Counties. Our Beta properties and associated facilities are subject to regulation by the SCAQMD.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Regulation of “Greenhouse Gas” Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the CAA. In addition, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, almost one-half of the states have taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. In addition, in December 2015, the United States joined the international community at the 21st Conference of the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit increase in the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect in November 2016 and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, in June 2017, the United States announced its withdrawal from the Paris Agreement, although the earliest possible effective date of withdrawal is November 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement.

Restrictions on GHG emissions that may be imposed could adversely affect the oil and natural gas industry. Any GHG regulation could increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric driven compression at facilities to obtain regulatory permits and approvals in a timely manner. While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

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In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations.

Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our development and production operations.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the U.S. Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. All of our current development and production activities, as well as proposed development plans, on federal lands, including those in the Pacific Ocean, require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Endangered Species Act

The federal Endangered Species Act (“ESA”) and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. The presence of protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations and financial position.

Occupational Safety and Health Act

We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on our assets. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and the development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the surface use and restoration of properties upon which wells are drilled;

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• the plugging and abandoning of wells;

• transportation of materials and equipment to and from our well sites and facilities;

• transportation and disposal of produced fluids and natural gas; and

• notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Sale and Transportation of Gas and Oil

The Federal Energy Regulatory Commission (“FERC”) approves the construction of interstate gas pipelines and the rates and service conditions for the interstate transportation of gas, oil and other liquids by pipeline. Although the FERC does not regulate the production of gas, the FERC exercises regulatory authority over wholesale sales of gas in interstate commerce through the issuance of blanket marketing certificates that authorize the wholesale sale of gas at market rates and the imposition of a code of conduct on blanket marketing certificate holders that regulate certain affiliate interactions. The FERC does not regulate the sale of oil or petroleum products or the construction of oil or other liquids pipelines. The FERC also has oversight of the performance of wholesale natural gas markets, including the authority to facilitate price transparency and to prevent market manipulation. In furtherance of this authority, the FERC imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a minimum level. The agency’s actions are intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

The FERC and other federal agencies, the U.S. Congress or state legislative bodies and regulatory agencies may consider additional proposals or proceedings that might affect the gas or oil industries. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other gas producers with which we compete.

The Beta properties include the San Pedro Bay Pipeline Company, which owns and operates an offshore crude pipeline. This pipeline is subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, must be just and reasonable and non-discriminatory. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with the FERC and posted publicly. The FERC has established a formulaic methodology for petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. Effective July 1, 2016, the current index for the five-year period ending July 2021 is the producer price index for finished goods plus an adjustment factor of 1.23 percent. The San Pedro Bay Pipeline Company uses the indexing methodology to change its rates.

The Outer Continental Shelf Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. BOEM/BSEE has established formal and informal complaint procedures for shippers that believe that have been denied open and nondiscriminatory access to transportation on the OCS.

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The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates all pipeline transportation in or affecting interstate or foreign commerce, including pipeline facilities on the OCS. The San Pedro Bay pipeline is subject to regulation by the PHMSA. The PHMSA has also proposed additional regulations for gas pipeline safety. For example, in March 2016, the PHMSA proposed a rule that, if adopted, would expand integrity management requirements beyond high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas, to apply to gas pipelines in newly defined “moderate consequence areas” that contain as few as five dwellings within the potential impact area. Many gas pipelines that were in place before 1970, and thus grandfathered from certain pressure testing obligations, would be required to be pressure tested to determine their maximum allowable operating pressures. Many gathering lines in rural areas that are currently not regulated at the federal level would also be covered by this proposal. More recently, in January 2017, the PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to an HCA. The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure. The timing for implementation of this rule is uncertain at this time due to the change in presidential administrations.

Moreover, effective April 2017, the PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to up to $209,002 per violation per day and up to $2,090,022 for a related series of violations. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Anti-Market Manipulation Laws and Regulations

The FERC with respect to the purchase or sale of natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction, the Federal Trade Commission with respect to petroleum and petroleum products, and the Commodity Futures Trading Commission with respect to commodity and futures markets, operating under various statutes have each adopted anti-market manipulation regulations, which prohibit, among other things, fraud and price manipulation in the respective markets. These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

State Regulation

Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, the baseline Texas severance tax on oil and gas is 4.6% of the market value of oil produced and 7.5% of the market value of gas produced and saved. A number of exemptions from or reductions of the severance tax on oil and gas production is provided by the State of Texas which effectively lowers the cost of production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

As of December 31, 2017, the Company had 281 employees. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Offices

Our principal executive office is located at 500 Dallas Street, Suite 1600, Houston, Texas 77002. Our main telephone number is (713) 490-8900.

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Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website at www.amplifyenergy.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the United States Securities and Exchange Commission (“SEC”). These documents are also available on the SEC website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our website also includes our Code of Business Conduct and Ethics and the charters of our audit committee and our compensation committee. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

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ITEM 1A. RISK FACTORS

Our business and operations are subject to many risks. The risks described below, in addition to the risks described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of this annual report, may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. You should carefully consider the following risk factors together with all of the other information included in this annual report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report could have a material adverse effect on our business, financial position, results of operations and cash flows and the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to Emergence from Bankruptcy

We emerged from bankruptcy in May 2017, which may adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our emergence from bankruptcy in May 2017 may adversely affect our business and relationships with customers, vendors, royalty or working interest owners, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

• key suppliers, vendors or other contract counterparties may terminate their relationships with us or require additional financial assurances or enhanced performance from us;

• our ability to renew existing contracts and compete for new business may be adversely affected;

• our ability to attract, motivate and/or retain key executives and employees may be adversely affected;

• employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and

• competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in our Predecessor’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

Our ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy, our asset divestiture processes and our recent reduction in force.

The success of our business depends on key personnel. Our ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances, including our asset divestiture processes and our recent reduction in force in February 2018. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or otherwise depart, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity, profitability, efficiency and execution.

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Risks Related to Our Business

We may be subject to risks in connection with divestitures and acquisitions.

In June 2017, we announced that the Company had engaged financial advisors to explore and evaluate potential strategic alternatives, including the marketing of certain non-core assets for sale. In July 2017, the Company launched a divestiture process for our assets in the South Texas region. In October 2017, the Company launched divestiture processes for our assets in the East Texas/Louisiana region and the Rockies region. We may sell any of these core or non-core assets in order to increase capital resources available for other core assets, create organizational and operational efficiencies or for other purposes. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets on terms we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific action.

In addition, in the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. As a result, our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.

The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financing activities.

The operating and financial restrictions and covenants in any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our such financing agreements that are not cured or waived within the appropriate time periods provided therein, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our Credit Facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our Credit Facility, the lenders could seek to foreclose on our assets.

The terms and conditions governing our indebtedness:

• require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

• increase our vulnerability to economic downturns and adverse developments in our business;

• limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

• place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

• place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and

• limit management’s discretion in operating our business.

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Our lenders periodically redetermine the amount we may borrow under our Credit Facility, which may materially impact our operations.

Our Credit Facility allows us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The borrowing base is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. Accordingly, declining commodity prices may have an impact on the amount we can borrow, which could affect our cash flows and ability to execute on our business plans. Any reduction in the borrowing base would materially and adversely affect our business and financing activities, limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on our debt obligations. In addition, as hedges roll off, the borrowing base is subject to further reduction. Our Credit Facility requires us to repay any deficiency over a certain period or pledge additional oil and gas properties to eliminate such deficiency, which we are required to do within 30 days of notice to do so. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the credit facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under the credit facility.

We may not be able to generate enough cash flow to meet our debt obligations and may be forced to take other actions to satisfy our debt obligations that may not be successful.  

We have historically funded our operations, including our operating and capital expenditures, our debt service obligations and our acquisitions primarily through cash generated from operations, amounts available under our Predecessor’s revolving credit facility or our Credit Facility, as applicable, and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices and due to the steep decline in commodity prices, our ability to obtain funding in the equity or capital markets has been and will continue to be, constrained, and there can be no assurances that our liquidity requirements will continue to be satisfied given current commodity prices. If our sources of liquidity are not sufficient to fund our current or future liquidity needs, including as a result of a decrease in the borrowing base under our Credit Facility, we may be required to take other actions, including those actions discussed below.

Our earnings and cash flow may vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Moreover and subject to certain limitations, we may be able to incur substantial additional indebtedness in the future. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative strategic actions or financing plans, such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments;

• seeking to raise additional capital;

• liquidating all or a portion of our hedge portfolio;

• seeking additional partners to develop our assets;

• reducing our planned capital program;

• continuing to take and potentially increasing, our cost saving measures to reduce costs, including renegotiation contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs; or

• revising or delaying our other strategic plans.

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We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could cause us to incur high transaction costs, may be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including our Credit Facility, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our debt instruments restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due.

We can provide no assurances that any alternative strategic action or financing plan undertaken will be successful in allowing us to meet our debt obligations or will result in additional liquidity. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our ability to make payments on our indebtedness and our business, financial condition, results of operations and cash flows.

We may be able to incur substantially more debt, which could exacerbate the risks associated with our indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our Credit Facility. If new debt is added to our current debt levels, the related risks that we now face could increase. These risks could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to satisfy our obligations under our outstanding indebtedness.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Interest Price Risk” included under Part II of this annual report for further information regarding interest rate sensitivity.

Oil, natural gas and NGL prices are volatile, due to factors beyond our control and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition.

Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:

• the regional, domestic and foreign supply of oil, natural gas and NGLs;

• the level of commodity prices and expectations about future commodity prices;

• the level of global oil and natural gas exploration and production;

• localized supply and demand fundamentals, including the proximity and capacity of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;

• the cost of exploring for developing, producing and transporting reserves;

• the price and quantity of foreign imports;

• political and economic conditions in oil producing countries;

• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• speculative trading in crude oil and natural gas derivative contracts;

• the level of consumer product demand;

• weather conditions and other natural disasters;

• risks associated with operating drilling rigs;

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• technological advances affecting exploration and production operations and overall energy consumption;

• domestic and foreign governmental regulations and taxes;

• the continued threat of terrorism and the impact of military and other action;

• the price and availability of competitors’ supplies of oil and natural gas and alternative fuels; and

• overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2017, the NYMEX-WTI oil future price ranged from a high of $110.53 per Bbl to a low of $26.21 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu. For the year ended December 31, 2017, the West Texas Intermediate posted prices ranged from a low of $42.53 per Bbl on June 21, 2017 to a high of $60.42 per Bbl on December 29, 2017 and NYMEX Henry Hub spot market price ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.65 per MMBtu on January 2, 2017. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and different pricing characteristics, have sustained depressed realized prices during this period and are generally correlated with the price of oil. A further or extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition.

If commodity prices decline further and remain depressed for a prolonged period, a significant portion of our development projects may become uneconomic and cause further write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and our ability to fund our operations.

As discussed above, oil, natural gas and NGL prices have experienced significant volatility over the past few years. A further or extended decline in commodity prices could render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would reduce our borrowing base and our ability to fund our operations.

No impairments were recognized for the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017. We recognized $183.4 million and $616.8 million of impairments for the years ended December 31, 2016 and 2015, respectively, related to certain properties in East Texas, South Texas, the Permian Basin, Wyoming and Colorado. A further or extended decline in commodity prices may cause us to recognize additional impairments in the value of our oil and natural gas properties. In addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may in the future incur impairment charges that could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our Credit Facility.

The failure to replace our proved oil and natural gas reserves could adversely affect our business, financial condition, results of operations, production and cash flows.

Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would materially and adversely affect our business, financial condition and results of operations.

Our acquisition and development operations will require additional capital that may not be available.

Our business is capital intensive and requires substantial expenditures to maintain currently producing wells, to make the acquisitions and/or conduct the development activities necessary to replace our reserves, to pay expenses and to satisfy our other obligations. Low oil and natural gas prices, declines in the trading prices of our debt and equity securities and concern about the global financial markets may limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, and could limit our ability to obtain additional or continued funding under our Credit Facility or obtain any funding at all.

If we reduce our capital spending in an effort to conserve cash, this would likely result in production being lower than anticipated, and could result in reduced revenues, cash flow from operations and income. Further, if the borrowing base under our Credit Facility decreases, or our revenues decrease, as a result of lower oil or natural gas prices or for any other reason, we may not be able to obtain the capital necessary to sustain our operations.

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Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.

We intend to maintain a portfolio of commodity derivative contracts covering at least 75% of our estimated production from proved developed producing reserves over a one-to-three year period at any given point in time. These commodity derivative contracts include natural gas, oil and NGL financial swaps. The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices and price expectations, at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets or other unforeseen events could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of a derivative contract and, accordingly, prevent us from realizing the benefit of such a derivative contract.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could significantly reduce our cash flow and adversely affect our financial condition.

The prices that we receive for our oil and natural gas production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX or ICE, that are used for calculating hedge positions. The prices we receive for our production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, our California oil typically has a lower gravity, and a portion has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil requires more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. These discounts, if significant, could reduce our cash flows and adversely affect our results of operations and financial condition.

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.

It is not possible to measure underground accumulations of oil or natural gas in an exact way. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.

In order to prepare our estimates, we must project production rates and timing of operating and development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary.

The process also requires economic assumptions about matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds.

Actual future production, oil prices, natural gas prices, revenues, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

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The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

The present value of future net cash flows from our proved reserves shown in this report, or standardized measure, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the FASB, we base the estimated discounted future net cash flows from our proved reserves on the trailing 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements, which is required by the SEC and FASB, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash flows.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes, but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then-realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of our development and production activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our development and production operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

• high costs, shortages or delivery delays of rigs, equipment, labor, electrical power or other services;

• unusual or unexpected geological formations;

• composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;

• unexpected operational events and conditions;

• failure of down hole equipment and tubulars;

• loss of wellbore mechanical integrity;

• failure, unavailability or shortage of capacity of gathering and transportation pipelines, or other transportation facilities;

• human errors, facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour natural gas;

• title problems;

• loss of drilling fluid circulation;

• hydrocarbon or oilfield chemical spills;

• fires, blowouts, surface craterings and explosions;

• surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids;

• delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements; and

• adverse weather conditions and natural disasters.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition and results of operations may be adversely affected. If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our business, financial condition, results of operations and cash flows.

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Expenses not covered by our insurance could have a material adverse effect on our financial position and results of operations.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, all of which could cause substantial financial losses. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The location of any properties and other assets near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. The occurrence of any of these or other similar events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension or disruption of operations, substantial revenue losses and repairs to resume operations.

We maintain insurance coverage against potential losses that we believe is customary in the industry. However, insurance against all operational risk is not available to us. These insurance policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. A liability, claim or other loss not fully covered by insurance could have a material adverse effect on our business, financial position, results of operations and cash flows.

The production from our Wyoming Bairoil properties could be adversely affected by the cessation or interruption of the supply of CO₂ to those properties.

We inject water and CO₂ into formations on substantially all of the Wyoming Bairoil properties to increase production of oil and natural gas. The additional production and reserves attributable to the use of enhanced recovery methods are inherently difficult to predict. If we are unable to produce oil and gas by injecting CO₂ in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected. Additionally, our ability to utilize CO₂ to enhance production is subject to our ability to obtain sufficient quantities of CO₂. If, under our CO₂ supply contracts, the supplier is unable to deliver its contractually required quantities of CO₂ to us, or if our ability to access adequate supplies is impeded, then we may not have sufficient CO₂ to produce oil and natural gas in the manner or to the extent that we anticipate, and our future oil and gas production volumes will be negatively impacted.

Many of our properties are in areas that may have been partially depleted or drained by offset wells.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.

Our expectations for future development activities are planned to be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. We cannot predict in advance of drilling, testing and analysis of data whether any particular drilling location will yield production in sufficient quantities to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Our ability to drill, recomplete and develop locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure and lease expirations. Because of these uncertainties, we cannot be certain of the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition, results of operations and cash flows.

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Part of our strategy involves using horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

• landing our wellbore in the desired drilling zone;

• staying in the desired drilling zone while drilling horizontally through the formation;

• running our casing the entire length of the wellbore; and

• being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to, the following:

• the ability to fracture stimulate the target reservoir formation as planned, including the planned number of stages;

• the ability to run tools the entire length of the wellbore during completion operations; and

• the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical, which could have a material adverse impact on our financial condition, results of operations and cash flows.

SEC rules could limit our ability to book additional PUDs in the future.

SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and will likely continue to limit our ability to book additional PUDs as we pursue our drilling program, especially in a time of depressed commodity prices. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.

The unavailability or high cost of rigs, equipment, supplies and crews could delay our operations, increase our costs and delay forecasted revenue.

Our industry is cyclical, and historically there have been periodic shortages of rigs, equipment, supplies and crew. Sustained declines in oil and natural gas prices may reduce the number of service providers for such rigs, equipment, supplies and crews, contributing to or resulting in shortages. Alternatively, during periods of higher oil and natural gas prices, the demand for rigs, equipment, supplies and crews is increased and can lead to shortages of, and increasing costs for, development equipment, supplies, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict the Company’s ability to drill the wells and conduct the operations that it currently has planned relating to the fields where our properties are located. In addition, some of our operations require supply materials for production, such as CO₂, which could become subject to shortages and increased costs. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and impact our development plan, which would thus affect our financial conduction, results of operations and our cash flows.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

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Development and production of oil and natural gas in offshore waters has inherent and historically higher risk than similar activities onshore.

Our offshore operations are subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than our other oil and natural gas activities. We are vulnerable to the risks associated with operating offshore California, including risks relating to:

• natural disasters such as earthquakes, tidal waves, mudslides, fires and floods;

• oil field service costs and availability;

• compliance with environmental and other laws and regulations;

• remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and

• failure of equipment or facilities.

In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our offshore operations are conducted in environmentally sensitive areas, including areas with significant residential populations and public and commercial infrastructure. An accidental oil spill or release on or related to offshore properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and damages could be material to our business, financial condition or results of operations and could subject us to criminal and civil penalties. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.

Adverse developments in our operating areas could adversely affect our business, financial condition, results of operations and cash flows.

Our properties are located in Texas, Louisiana, offshore Southern California, and Wyoming. An adverse development in the oil and natural gas business of any of these geographic areas, such as in our ability to attract and retain field personnel or in our ability to comply with local regulations, could adversely affect our business, financial condition, results of operations and cash flows.

We are dependent upon a small number of significant customers for a substantial portion of our production sales.The loss of those customers, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition and results of operations.

We had four customers that each accounted for 10% or more of total reported revenues for the period from May 5, 2017 through December 31, 2017. We had three customers that each accounted for 10% or more of total reported revenues for the period from January 1, 2017 through May 4, 2017. The loss of these customers or any significant customer, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. Also, if any significant customer reduces the volume it purchases from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our production, and our revenues and cash flows could decline. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production. See “Item 1. Business — Operations — Marketing and Major Customers.”

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

We are subject to credit risk due to concentration of our oil and natural gas receivables. The inability or failure of our significant customers, or any purchasers of our production, to meet their payment obligations to us or their insolvency or liquidation could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and cash flows.

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We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors and other counterparties. Some of our vendors and other counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors and other counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’ and other counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors and/or counterparties could adversely affect our business, financial condition, results of operations and cash flows.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be unable to compete effectively with larger companies.

The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis and many of our competitors have access to capital at a lower cost than that available to us. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition, results of operations and cash flows.

Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. For example, our ability to produce and sell oil from the Beta properties will depend on the availability of the pipeline infrastructure between platforms as well as the San Pedro Bay Pipeline for delivery of that oil to shore, and any unavailability of that pipeline infrastructure or pipeline could cause us to shut in all or a portion of the production from the Beta properties for the length of such unavailability. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business, financial condition, results of operations and cash flows.

We have limited control over the activities on properties we do not operate.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.

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We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations administered by governmental authorities vested with broad authority relating to the exploration for and the development, production and transportation of, oil and natural gas, as well as environmental and safety matters. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, the trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Further, the Mineral Leasing Act of 1920, as amended (the “Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. It is possible that our stockholders may be citizens of foreign countries who do not own their stock in a U.S. corporation, or that even if such stock are held through a U.S. corporation, their country of citizenship may be determined to be non-reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.

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Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the CAA. In addition, the EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, almost one-half of the states have taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. In addition, in December 2015, the United States joined the international community at the 21st Conference of the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement, which went into effect in November 2016, establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, in June 2017, the United States announced its withdrawal from the Paris Agreement, although the earliest possible effective date of withdrawal is November 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.

The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs, new operating restrictions, or delays in our operations, which could adversely affect our results of operations and financial condition.

The ESA and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our activities in those areas or during certain seasons, such as breeding and nesting seasons. The listing of species in areas where we operate or, alternatively, entry into certain range-wide conservation planning agreements could result in increased costs to us from species protection measures, time delays or limitations on our activities, which costs, delays or limitations may be significant and could adversely affect our results of operations and financial position.

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations. See “Item 1. Business — Environmental, Occupational Health and Safety Matters and Regulations” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.

42

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (“CFTC”), the SEC, and federal regulators of financial institutions (the “Prudential Regulators”), adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.

Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued a large number of rules, including a rule, which we refer to as the “Clearing Rule,” requiring clearing of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps, which we do not presently have), a rule establishing an “end user” exception to the Clearing Rule, referred to herein as the “End User Exception,” a rule, which we refer to as the “Margin Rule,” setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the “Non-Financial End User Exception,” and a rule, subsequently vacated by the United States District Court for the District of Columbia and remanded to the CFTC for further proceedings, imposing position limits. The CFTC proposed a new version of this rule, with respect to which the comment period closed but the rule was not adopted, and another new version of this rule, which we refer to as the “Re-Proposed Position Limit Rule,” with respect to which the comment period has closed but a final rule has not been issued. The Re-Proposed Position Limit Rule provides an exemption from the position limits for swaps that constitute “bona fide hedging positions” within the definition of such term under the Re-Proposed Position Limit Rule, subject to the party claiming the exemption complying with the applicable filing, recordkeeping and reporting requirements of the Re-Proposed Position Limit Rule.

We currently qualify for the End User Exception and will utilize it if the Clearing Rule is expanded to cover swaps in which we participate; we currently qualify for the Non-Financial End User Exception and will not be required to post margin under the Margin Rule, and our existing and anticipated hedging positions constitute “bona fide hedging positions” under the Re-Proposed Position Limit Rule and we intend to do the filing, recordkeeping and reporting necessary to utilize the bona fide hedging position exemption under the Re-Proposed Position Limit Rule if and when it becomes effective, so we do not expect to be directly affected by any of such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (including laws and regulations giving European Union financial authorities the power to write down amounts we may be owed on hedging agreements with counterparties subject to such laws and regulations and/or require that we accept equity interests in such counterparties in lieu of cash in satisfaction of such amounts), which we refer to collectively as “Foreign Regulations” which may apply to our transactions with counterparties subject to such Foreign Regulations. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Re-Proposed Position Limit Rule is ultimately effected, such proposed rule could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations and Foreign Regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

43

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water and the disposal of waste, including produced water and drilling fluids. Restrictions on the ability to obtain water may impact our operations.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our development and production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The Clean Water Act (“CWA”) imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Also, the EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and adversely affect our production.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We routinely apply hydraulic fracturing techniques in our drilling and completion programs. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. See “Item 1. Business — Environmental, Health and Safety Matters and Regulations — Hydraulic Fracturing” for a description of the federal and state legislative and regulatory initiatives relating to hydraulic fracturing that affect us.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes further regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. The U.S. Congress has from time to time considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

In addition, certain governmental reviews have been conducted that focus on environmental aspects of hydraulic fracturing practices, which could lead to increased regulation. For example, in December 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, in February 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey and the U.S. Government Accountability Office, have evaluated various other aspects of hydraulic fracturing. In addition, as discussed above, BOEM and BSEE completed a study in May 2016 regarding the potential environmental impacts of well-stimulation practices on the Pacific OCS. Such studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

The cost of decommissioning is uncertain.

We are required to maintain reserve funds to provide for the payment of decommissioning costs associated with the Beta properties. The estimates of decommissioning costs are inherently imprecise and subject to change due to changing cost estimates, oil and natural gas prices and other factors. If actual decommissioning costs exceed such estimates, or we are required to provide a significant amount of collateral in cash or other security as a result of a revision to such estimates, our financial condition, results of operations and cash flows may be materially adversely affected.

44

Our business could be adversely affected by security threats, including cyber-security threats, and related disruptions.

As a producer of natural gas and oil, we face from time to time various security threats, including cyber-security threats, to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing and other facilities, refineries and pipelines. These security threats subject our operations to increased risks that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. If any security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position, results of operations and cash flows.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the Tax Cuts and Jobs Act of 2017 (which was signed on December 22, 2017), Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. It is unclear whether any of the foregoing or similar proposals will be considered and enacted as part of future tax reform legislation and if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development and any such change could have an adverse effect on the Company’s financial position, results of operations and cash flows.

Recent changes in United States federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition overall.

The Tax Cuts and Jobs Act of 2017 may affect our cash flows, results of operations and financial condition. Among other items, the Tax Cuts and Jobs Act of 2017 repealed the deduction for certain U.S. production activities and provided for a new limitation on the deduction for interest expense. Given the scope of this law and the potential interdependency of its changes, it is difficult at this time to assess whether the overall effect of the Tax Cuts and Jobs Act of 2017 will be cumulatively positive or negative for our earnings and cash flow, but such changes may adversely impact our financial results.

Risks Relating to Our Common Stock

The price and trading volume of our common stock may fluctuate significantly.

The market price of our common stock may be highly volatile and could be subject to wide fluctuations. In addition, the trading volume of our common stock may fluctuate and cause significant price variations to occur. Volatility in the market price of our common stock may prevent you from being able to sell your shares at or above the price at which you were granted your shares of common stock or above the price you paid to acquire your shares of common stock. The market price for our common stock could fluctuate significantly for various reasons, including:

• our new capital structure as a result of the transactions contemplated by the Plan;

• our limited trading history subsequent to our emergence from the Chapter 11 Cases;

• our limited trading volume;  

• the lack of comparable historical financial information due to our adoption of fresh start accounting;  

• actual or anticipated variations in our operating results and cash flow;  

• the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets; and  

• business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions.

45

We currently have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common stock.

We currently have no plans to pay regular dividends on our common stock. Any payment of dividends in the future will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition and business opportunities, the restrictions in our debt agreements, and other considerations that our board of directors deems relevant. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information regarding our properties is contained in “Item 1. Business — Our Areas of Operation” and “—Our Oil and Natural Gas Data” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” contained herein.

ITEM 3. LEGAL PROCEEDINGS

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows. No amounts have been accrued at December 31, 2017.

For additional information regarding legal proceedings, see Note 15, “Commitments and Contingencies — Litigation and Environmental” of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report, which is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

46

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

In connection with our reorganization and emergence from bankruptcy, all of our Predecessor’s common units, formerly traded under the symbol “MEMP,” were canceled. On June 21, 2017, our Successor’s common stock was listed on the OTCQX U.S. Premier marketplace (“OTCQX”) under the symbol “AMPY.” Prior to such time, there was no established trading market for our common stock.

The market data below represents the high and low bid information for our common stock as reported on OTCQX:

	Common Stock
	Price Range
	High		Low
2017
4th Quarter	$	11.62	$	9.01
3rd Quarter	$	11.50	$	8.85
2nd Quarter (from June 21, 2017)	$	11.00	$	9.00

Such over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

As of February 28, 2018, we had 25,000,000 shares of our common stock outstanding. As of February 28, 2018, we had seven record holders of our common stock, based on information provided by our transfer agent.

Dividends Policy

We have not paid, nor do we currently intend in the foreseeable future to pay, any cash dividends on our common stock.

Securities Authorized for Issuance Under Equity Compensation Plan

See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” for information regarding shares of our common stock authorized for issuance under our stock compensation plans, which information is incorporated herein by reference.

Sales of Unregistered Securities

On the Effective Date, in connection with our emergence from bankruptcy, we issued (i) 25,000,000 shares of our common stock and (ii) 2,173,913 warrants to purchase 2,173,913 shares of our common stock, in exchange for certain claims against and interests in the Company. We relied on the exemption from registration provided by Section 1145 of the Bankruptcy Code.

Issuer Purchases of Equity Securities

During the three months ended December 31, 2017, there were no repurchases of our common stock.

47

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.

Basis of Presentation. The selected financial data as of and for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and for the years ended December 31, 2016, 2015, 2014 and 2013 have been derived from our consolidated financial statements and the previous owners’ combined financial statements. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, the WHT Properties owned by WHT from February 2, 2011 (inception) through the date of acquisition, the Cinco Group from inception through October 1, 2013 and the Property Swap in February 2015 for periods after common control commenced through the date of acquisition. The combined selected financial data of the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor operated those assets separately during those periods.

Comparability of the information reflected in selected financial data. The comparability of the results of operations among the periods presented below is impacted by the following acquisitions:

• The acquisition of certain oil and natural gas producing properties in the Eagle Ford from a third party in March 2014 for a total purchase price of approximately $168.1 million;

• The acquisition of certain oil and natural gas liquids properties in Wyoming from a third party in July 2014 for a total purchase price of approximately $906.1 million;

• The acquisition of the remaining interest in the Beta properties from a third party in November 2015 for approximately $94.6 million;

• The sale of assets located in the Permian Basin (the “Permian Divestiture”) in June 2016 for approximately $36.7 million; and

• The sale of assets located in Colorado and Wyoming (the “Rockies Divestiture”) in July 2016 for approximately $16.4 million

In addition, the comparability of the results of operations among the periods presented below is impacted by the application of fresh start accounting. The Company’s Consolidated and Combined Financial Statements are separated into two distinct periods, the period before the Effective Date (labeled Predecessor), and the period after that date (labeled Successor), to indicate the application of different basis of accounting between the periods presented.

48

As a result of the factors listed above, the combined historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017
	through			through			For the Year Ended December 31,
($ in thousands, except per share/unit data)	December 31, 2017			May 4, 2017			2016			2015			2014			2013
Statement of Operations Data:
Revenues:
Oil & natural gas sales	$	205,176		$	108,970		$	284,051		$	355,422		$	561,677		$	391,440
Pipeline tariff income and other		303			231			529			2,725			4,366			3,075
Total revenues		205,479			109,201			284,580			358,147			566,043			394,515
Costs and expenses:
Lease operating expense		74,547			35,568			126,175			168,199			143,733			94,591
Gathering, processing and transportation		18,652			10,772			34,979			34,939			31,892			25,055
Exploration		32			21			981			2,317			2,750			1,322
Taxes other than income		11,101			5,187			15,540			25,828			33,141			18,447
Depreciation, depletion and amortization		35,979			37,717			171,629			195,814			185,955			113,814
Impairment of proved oil and natural gas properties		—			—			183,437			616,784			407,540			4,072
General and administrative expense		29,506			31,606			63,280			56,671			49,124			54,947
Accretion of asset retirement obligations		4,384			3,407			10,231			7,125			5,773			4,988
(Gain) loss on commodity derivative instruments		31,609			(23,076	)		117,105			(462,890	)		(492,254	)		(26,133	)
Gain (loss) on sale of properties		—			—			(2,754	)		(2,998	)		—			(2,848	)
Other, net		485			36			516			(665	)		(11	)		647
Total costs and expenses		206,295			101,238			721,119			641,124			367,643			288,902
Operating income (loss)		(816	)		7,963			(436,539	)		(282,977	)		198,400			105,613
Other income (expense):
Interest expense, net		(15,936	)		(10,243	)		(146,031	)		(115,154	)		(83,550	)		(44,302	)
Other income (expense)		16,981			8			8			43			(657	)		2
Gain on extinguishment on debt		—			—			42,337			422			—			—
Total other income (expense)		1,045			(10,235	)		(103,686	)		(114,689	)		(84,207	)		(44,300	)
Income (loss) before reorganization items, net and income taxes		229			(2,272	)		(540,225	)		(397,666	)		114,193			61,313
Reorganization items, net		(1,119	)		(88,774	)		—			—			—			—
Income tax benefit (expense)		2,176			91			(173	)		2,175			1,421			(308	)
Net income (loss)		1,286			(90,955	)		(540,398	)		(395,491	)		115,614			61,005
Net income (loss) attributable to noncontrolling interest		—			—			—			386			32			267
Net income (loss) attributable to Successor/Predecessor	$	1,286		$	(90,955	)	$	(540,398	)	$	(395,877	)	$	115,582		$	60,738
Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor	$	1,286		$	(90,955	)	$	(540,398	)	$	(395,877	)	$	115,582		$	60,738
Net (income) loss allocated to previous owners		—			—			—			2,268			2,465			(52,012	)
Net (income) loss allocated to Predecessor's general partner		—			—			168			327			(206	)		(49	)
Net (income) loss allocated to NGP IDRs		—			—			—			(83	)		(88	)		—
Net (income) allocated to participating restricted stockholders		(35	)		—			—			—			—			—
Net income (loss) available to common stockholders/limited partners	$	1,251		$	(90,955	)	$	(540,230	)	$	(393,365	)	$	117,753		$	8,677
Earnings per share/unit:
Basic earnings per share/unit	$	0.05		$	(1.09	)	$	(6.48	)	$	(4.71	)	$	1.66		$	0.19
Diluted earnings per share/unit	$	0.05		$	(1.09	)	$	(6.48	)	$	(4.71	)	$	1.66		$	0.19
Predecessor's cash distributions declared per unit	n/a			n/a			$	0.16		$	1.95		$	2.20		$	2.08
Cash Flow Data:
Net cash flow provided by operating activities	$	102,203		$	117,937		$	408,626		$	216,751		$	254,273		$	201,703
Net cash (used in) investing activities		(53,357	)		(6,496	)		(16,442	)		(337,569	)		(1,386,109	)		(214,559	)
Net cash provided by (used in) financing activities		(62,594	)		(106,674	)		(377,410	)		120,447			1,111,108			5,969
Balance Sheet Data:
Working capital (deficit)	$	35,948		$	59,527		$	(1,581,193	)	$	246,778		$	150,953		$	(3,067	)
Total assets		917,464			981,427			1,973,254			2,906,003			3,168,494			1,834,315
Current portion of long-term debt (1)		—			—			1,622,904			—			—			—
Long-term debt (1)		376,000			430,000			—			2,000,579			1,574,147			777,014
Total equity		393,933			390,140			99,489			645,492			1,296,314			863,021

(1) Due to the existing and anticipated financial covenant violations at December 31, 2016, the borrowings under the Predecessor’s revolving credit facility and the Notes were classified as current at December 31, 2016. There were no existing or anticipated financial covenant violations as of December 31, 2017.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” contained herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I, Item 1A. of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Forward-Looking Statements” in the front of this report.

References

When referring to Amplify Energy Corp. (also referred to as “Successor,” “Amplify Energy,” or the “Company”), the intent is to refer to Amplify Energy, a Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Amplify Energy is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to the “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

Overview

Amplify Energy is an independent oil and natural gas company that was formed on March 21, 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from December 2011 to May 2017. As discussed further below and in Note 2 of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data”, on January 16, 2017 (the “Petition Date”), MEMP and certain of its subsidiaries (collectively with MEMP, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re: Memorial Production Partners LP, et al. (Case No. 17-30262). During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective May 4, 2017 (the “Effective Date”).

We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on the 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 and are located in Texas, Louisiana, Wyoming and offshore Southern California. 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, 2017:

• Our total estimated proved reserves were approximately 989.7 Bcfe, of which approximately 44% were oil and 71% were classified as proved developed reserves;

• We produced from 2,547 gross (1,498 net) producing wells across our properties, with an average working interest of 59%, and the Company is the operator of record of the properties containing 93% of our total estimated proved reserves; and

• Our average net production for the three months ended December 31, 2017 was 184.3 MMcfe/d, implying a reserve-to-production ratio of approximately 15 years.

Recent Developments

Emergence from Voluntary Reorganization under Chapter 11

On April 14, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) approving the Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (as amended and supplemented, the “Plan”).

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On the Effective Date, the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and the Company emerged from bankruptcy. Although the Company is no longer in a debtor in possession, the Company was a debtor in possession from January 16, 2017 through May 4, 2017. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial and results of operations for the period presented.

Upon emergence from the Chapter 11 proceedings on May 4, 2017, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims.

See Notes 2 and 3 of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for additional information.

Reduction in Force

In February 2018, certain employees were impacted by a workforce reduction resulting in the involuntary termination of 19 employees across the Company.

Departure of Director

On January 9, 2018, Alex Shayevsky resigned from the board of directors. Mr. Shayevsky served on our audit committee and compensation committee. There were no disagreements between Mr. Shayevsky and us which led to Mr. Shayevsky’s resignation from the board.

Borrowing Base Redetermination and First Amendment to Credit Facility

In November 2017, we completed the scheduled redetermination of our Credit Facility borrowing base and entered into the first amendment to our credit agreement. The redetermination resulted in a revised borrowing base of $450.0 million beginning in November 2017 with scheduled monthly reductions of $2.5 million until the borrowing base reaches $437.5 million in April 2018. The next regularly scheduled borrowing base redetermination is expected to occur in April 2018. See Note 10 of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for additional information regarding the Credit Facility.

Divestiture Processes

In July 2017, we launched a divestiture process for our assets in the South Texas region. In October 2017, we launched divestiture processes for our assets in the East Texas/Louisiana region and the Rockies region.

Third-Party Midstream Transaction

In October 2017, we recognized an approximate $17.0 million gain in connection with the sale of a third-party midstream entity with whom our natural gas gathering and processing agreements entitled us to a percentage of the proceeds in the event of a sale.

Predecessor and Successor Reporting

As a result of the application of fresh start accounting, the Company’s Consolidated and Combined Financial Statements and certain note presentations are separated into two distinct periods, the period before the Effective Date (labeled Predecessor) and the period after that date (labeled Successor), to indicate the application of different basis of accounting between the periods presented. Despite this separate presentation, there was continuity of the Company’s operations.

See Note 3 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information related to our adoption of fresh start accounting.

Business Environment and Operational Focus

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production; (iii) cash settlements on our commodity derivatives; (iv) lease operating expense; (v) gathering, processing and transportation; (vi) general and administrative expense; and (vii) Adjusted EBITDA.

Production Volumes

Production volumes directly impact our results of operations. For more information about our volumes, see “— Results of Operations” below.

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Realized Prices on the Sale of Oil and Natural Gas

We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, realized prices are heavily influenced by product quality and location relative to consuming and refining markets.

Natural Gas. The NYMEX-Henry Hub future price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas can differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO₂ and other inert content by volume. Natural gas with a high Btu content (“wet” natural gas) sells at a premium to natural gas with low Btu content (“dry” natural gas) because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO₂ content sells at a premium to natural gas with high sulfur and CO₂ content because of the added cost required to separate the sulfur and CO₂ from the natural gas to render it marketable. Wet natural gas may be processed in third-party natural gas plants, where residue natural gas as well as NGLs are recovered and sold. At the wellhead, our natural gas production typically has an average energy content greater than 1,000 Btu and minimal sulfur and CO₂ content and generally receives a premium valuation. The dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the produced natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Historically, these index prices have generally been at a discount to NYMEX-Henry Hub natural gas prices.

Oil. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The ICE Brent futures price is a widely used global price benchmark for oil. The actual prices realized from the sale of oil can differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil’s American Petroleum Institute (“API”) gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil (“sour” oil).

Location differentials result from variances in transportation costs based on the produced oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential).

The oil produced from our onshore properties is a combination of sweet and sour oil, varying by location. This oil is typically sold at the NYMEX-WTI price, adjusted for quality and transportation differential, depending primarily on location and purchaser. The oil produced from our Beta properties is heavy and sour oil. Oil produced from our Beta properties is currently sold based on refiners’ posted prices for California Midway-Sunset deliveries in Southern California, adjusted primarily for quality and a negotiated market differential.

Price Volatility. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. The following table shows the low and high commodity future index prices for the periods indicated:

	High		Low
For the Year Ended December 31, 2017:
NYMEX-WTI oil future price range per Bbl	$	60.42	$	42.53
NYMEX-Henry Hub natural gas future price range per MMBtu	$	3.65	$	2.44
ICE Brent oil future price range per Bbl	$	67.02	$	44.82
For the Five Years Ended December 31, 2017:
NYMEX-WTI oil future price range per Bbl	$	110.53	$	26.21
NYMEX-Henry Hub natural gas future price range per MMBtu	$	7.94	$	1.49
ICE Brent oil future price range per Bbl	$	118.90	$	27.88

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Commodity Derivative Contracts. Our hedging activities are intended to support oil, NGL and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 75% of our estimated production from proved developed producing reserves over a one-to-three year period at any given point of time to satisfy the hedging covenants in our Credit Facility and pursuant to our internal policies. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts.

Principal Components of Cost Structure

• Lease operating expense. These are the day to day costs incurred to maintain production of our natural gas, NGLs and oil. Such costs include utilities, direct labor, water injection and disposal, the cost of CO₂ injection, chemicals, materials and supplies, compression, repairs and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services and activities performed during a specific period.

• Gathering, processing and transportation. These are costs incurred to deliver production of our natural gas, NGLs and oil to the market. Cost levels of these expenses can vary based on the volume of natural gas, NGLs and oil production.

• Exploration expense. These are geological and geophysical costs and include certain seismic costs, costs of unsuccessful exploratory dry holes and unsuccessful leasing efforts.

• Taxes other than income. These consist of production, ad valorem and franchise taxes. Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. We take advantage of credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties. Franchise taxes are privilege taxes levied by states that are imposed on companies, including limited liability companies and partnerships, which gives the businesses the right to be chartered or operate within that state.  

• Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, exploit and develop oil and natural gas properties. As a “successful efforts” company, all costs associated with acquisition and development efforts and all successful exploration efforts are capitalized, and these costs are depleted using the units of production method.

• Impairment of proved oil and natural gas properties. Proved properties are impaired whenever the net carrying value of the properties exceed their estimated undiscounted future cash flows.

• General and administrative expense. These costs include overhead, including payroll and benefits for employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expense associated with certain long-term incentive-based plans, audit and other professional fees and legal compliance expenses.

Prior to June 1, 2016, Memorial Resource provided management, administrative and operating services to the Predecessor and the Predecessor’s general partner pursuant to our Predecessor’s Omnibus Agreement. Upon completion of the MEMP GP Acquisition, the Predecessor’s Omnibus Agreement was terminated on June 1, 2016 and the Predecessor entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 1 and Note 14 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

• Accretion expense. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value.

• Interest expense. Historically, we financed a portion of our working capital requirements, capital development and acquisitions with borrowings under our Credit Facility, our Predecessor’s revolving credit facility and the Predecessor’s senior note issuances. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and financing decisions. We expect to continue to incur significant interest expense.

• Income tax expense. We are a corporation subject to federal and certain state income taxes. Our Predecessor was organized as a pass-through entity for federal and most state income tax purposes. During the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015, certain of our consolidated subsidiaries were taxed as corporations for federal and state income tax purposes. We are subject to the Texas margin tax for activities in the State of Texas.

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Outlook

Based on our current drilling plans, our capital expenditure program for the full year 2018 is expected to be approximately $65 to $80 million. The charts below detail the allocation of capital across our asset base and by investment type based on the midpoint of our 2018 capital expenditure range. The majority of our capital is expected to be spent on horizontal drilling activities in East Texas. The amounts noted below are in millions:

As has been our historical practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity prices, drilling success and other factors. To the extent our 2018 capital requirements exceed our internally generated cash flow, we may fund these requirements with proceeds from asset sales, borrowings under our revolving credit facility, and/or debt or equity financings.

Critical Accounting Policies and Estimates

Fresh Start Accounting

Upon the Effective Date, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims. Fresh start accounting involved a comprehensive valuation process in which we determined the fair value of all of our assets and liabilities on the Effective Date. See Note 3 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information related to our adoption of fresh start accounting.

Use of Estimates

The preparation of Consolidated and Combined Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated and Combined Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs attributable to unproved locations are expensed as incurred.

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As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Support equipment and facilities, which are primarily related to our Rockies and California assets, are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.

Oil and Natural Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the Consolidated and Combined Financial Statements are estimated in accordance with the rules established by the SEC and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged Ryder Scott, our independent reserve engineers, to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2017.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production or drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.  

Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses.

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps) are used to reduce the impact of natural gas and oil price fluctuations. Every derivative instrument is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings as we have not elected hedge accounting for any of our derivative positions.

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Results of Operations

The results of operations for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017, and the years ended December 31, 2016 and 2015 have been derived from both our consolidated financial statements and our previous owners’ combined financial statements. The previous owners combined financial statements reflect certain oil and gas properties primarily located in East Texas and Louisiana acquired from Memorial Resource in February 2015 for periods after common control commenced through the date of acquisition. The results of operations attributable to the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor operated separately during those periods.

Factors Affecting the Comparability of the Combined Historical Financial Results

The comparability of the results of operations among the periods presented is impacted by the following significant transactions:

• The acquisition of the remaining interest in the Beta properties (“2015 Beta Acquisition”) from a third party in November 2015 for approximately $94.6 million.

• The sale of assets located in the Permian Basin (the “Permian Divestiture”) in June 2016 for approximately $36.7 million.

• The sale of assets located in Colorado and Wyoming (the “Rockies Divestiture”) in July 2016 for approximately $16.4 million.

In addition, the comparability of the results of operations among the periods presented below is impacted by the application of fresh start accounting. The Company’s Consolidated and Combined Financial Statements are separated into two distinct periods, the period before the Effective Date (labeled Predecessor) and the period after that date (labeled Successor), to indicate the application of different basis of accounting between the periods presented.

As a result of the factors listed above, the combined historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

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The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017			For the Year Ended
	through			through			December 31,
	December 31, 2017			May 4, 2017			2016			2015
	(In thousands)			(In thousands)
Oil and natural gas sales	$	205,176		$	108,970		$	284,051		$	355,422
Lease operating expense		74,547			35,568			126,175			168,199
Gathering, processing and transportation		18,652			10,772			34,979			34,939
Taxes other than income		11,101			5,187			15,540			25,828
Depreciation, depletion and amortization		35,979			37,717			171,629			195,814
Impairment of proved oil and natural gas properties		—			—			183,437			616,784
General and administrative expense		29,506			31,606			63,280			56,671
Accretion of asset retirement obligations		4,384			3,407			10,231			7,125
(Gain) loss on commodity derivative instruments		31,609			(23,076	)		117,105			(462,890	)
(Gain) loss on sale of properties		—			—			(2,754	)		(2,998	)
Interest expense, net		(15,936	)		(10,243	)		(146,031	)		(115,154	)
Other income (expense)		16,981			8			8			43
Gain on extinguishment of debt		—			—			42,337			422
Reorganization items, net		(1,119	)		(88,774	)		—			—
Income tax benefit (expense)		2,176			91			(173	)		2,175
Net income (loss)		1,286			(90,955	)		(540,398	)		(395,491	)
Oil and natural gas revenue:
Oil sales	$	112,123		$	55,767		$	143,456		$	177,711
NGL sales		26,817			14,103			33,137			43,102
Natural gas sales		66,236			39,100			107,458			134,609
Total oil and natural gas revenue	$	205,176		$	108,970		$	284,051		$	355,422
Production volumes:
Oil (MBbls)		2,380			1,204			3,883			4,087
NGLs (MBbls)		1,114			616			2,286			2,820
Natural gas (MMcf)		21,885			12,411			44,776			50,875
Total (MMcfe)		42,850			23,336			81,773			92,315
Average net production (MMcfe/d)		177.8			188.2			223.4			252.9
Average sales price:
Oil (per Bbl)	$	47.11		$	46.28		$	36.94		$	43.48
NGL (per Bbl)		24.07			22.90			14.52			15.28
Natural gas (per Mcf)		3.03			3.15			2.40			2.65
Total (per Mcfe)	$	4.79		$	4.67		$	3.47		$	3.85
Average unit costs per Mcfe:
Lease operating expense	$	1.74		$	1.52		$	1.54		$	1.82
Gathering, processing and transportation		0.44			0.46			0.43			0.38
Taxes other than income		0.26			0.22			0.19			0.28
General and administrative expense		0.69			1.35			0.77			0.61
Depletion, depreciation and amortization		0.84			1.62			2.10			2.12

For the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016

Net income of $1.3 million, a net loss of $91.0 million and a net loss of $540.4 million was recorded for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively.

• Oil, natural gas and NGL revenues were $205.2 million, $109.0 million and $284.1 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. Average net production volumes were approximately 177.8 MMcfe/d, 188.2 MMcfe/d and 223.4 MMcfe/d for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 to May 4, 2017 and the year ended December 31, 2016, respectively. The change in production volumes was primarily related to decreases in drilling activities and divestitures. The average realized sales price was $4.79 per Mcfe, $4.67 per Mcfe and $3.47 per Mcfe for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. The change in the average realized sales price was primarily due to increases in realized prices for oil, natural gas and NGLs.

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• Lease operating expense was $74.5 million, $35.6 million and $126.2 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. The change in lease operating expense was the result of decreased workover activity and the Permian Divestiture and Rockies Divestiture. On a per Mcfe basis, lease operating expense was $1.74, $1.52 and $1.54 for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. The change in lease operating expense on a per Mcfe basis was primarily related to lower production.

• Gathering, processing and transportation expenses were $18.7 million, $10.8 million and $35.0 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. The change in gathering, processing and transportation was primarily due to lower production. On a per Mcfe basis, gathering, processing and transportation expenses were $0.44, $0.46 and $0.43 for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively.

• Taxes other than income was $11.1 million, $5.2 million and $15.5 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. On a per Mcfe basis, taxes other than income were $0.26, $0.22 and $0.19 for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. The change in taxes other than income on a per Mcfe basis was primarily due to an increase in commodity prices.

• DD&A expense was $36.0 million, $37.7 million and $171.6 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. The change in DD&A expense was primarily due to lower rates as a result of the application of fresh start accounting and a decrease in production volumes.

• No impairments were recognized for the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017. We recognized $183.4 million of impairments for the year ended December 31, 2016 related to certain properties in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to a downward revision of estimated proved reserves as a result of significant declines in commodity prices. For additional information, see Note 6 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

• General and administrative expense was $29.5 million, $31.6 million and $63.3 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. Non-cash share/unit-based compensation expense was approximately $2.5 million, $3.7 million and $7.4 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. Additionally, the Company recorded $7.5 million in pre-petition restructuring-related costs primarily for advisory and professional fees for the period from January 1, 2017 through May 4, 2017.

• Net losses on commodity derivative instruments of $31.6 million were recognized for the period from May 5, 2017 through December 31, 2017, consisting of $30.4 million of cash settlements received on expired positions offset by a $62.0 million decrease in the fair value of open positions. Net gains on commodity derivative instruments of $23.1 million were recognized for January 1, 2017 through May 4, 2017, consisting of $15.9 million of cash settlements received on expired positions and $94.1 million in cash settlements received on terminated derivatives. These receipts were partially offset by an $86.9 million decrease in the fair value of open positions. Net losses on commodity derivative instruments of $117.1 million were recognized for the year ended December 31, 2016, consisting of $212.6 million of cash settlements received on expired positions and $230.7 million in cash settlements received on terminated derivatives. These gains were offset by a $560.4 million decrease in the fair value of open positions.

Given the volatility of commodity prices, it is not possible to predict future reported unrealized mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

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• Interest expense, net was $15.9 million, $10.2 million and $146.0 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. The change in interest expense was primarily due to the Company not recording interest expense on the Notes for the period from the Petition Date through the Effective Date. The Company recorded $3.5 million and $84.1 million in interest expense related to the Notes for the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. No interest expense was recorded on the Notes for the period from May 5, 2017 through December 31, 2017, as the Notes were cancelled on the Effective Date. The Company recognized $2.1 million and $22.1 million in amortization and write-off of deferred financing cost for the period from May 5, 2017 through December 31, 2017 and the year ended December 31, 2016, respectively. No amortization of deferred financing cost was recorded for the period from January 1, 2017 through May 4, 2017, as the unamortized amount of deferred financing cost was written off in the fourth quarter of 2016. The Company recorded $13.2 million of accretion of the Notes discount for the year ended December 31, 2016. No expense was recorded for the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017, as the unamortized amount of accretion of the Notes discount was written off in the fourth quarter of 2016.

Average outstanding borrowings under our Credit Facility were $406.4 million for the period from May 5, 2017 through December 31, 2017. Average outstanding borrowings under the Predecessor’s revolving credit facility were $460.2 million $746.0 million for the period from January 1, 2017 through May 4, 2017 and for the year ended December 31, 2016, respectively. We had an average of $1.1 billion aggregate principal amount of the Notes issued and outstanding for the period from January 1, 2017 through May 4, 2017 and for the year ended December 31, 2016, respectively. The Notes were cancelled on the Effective Date.

• The Company incurred significant costs associated with the reorganization. Reorganization items, net represents costs and income directly associated with the Chapter 11 proceedings since the Petition Date, such as the gain on settlement of liabilities subject to compromise, fresh start valuation adjustments and professional fees. The Company incurred $1.1 million and $88.8 million of reorganization items, net for the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. See Note 3 of the Notes to the Consolidated and Combined Financial Statements under “Item 8. Financial Statements and Supplementary Data” of this annual report for additional information.

• Other income (expense) was $17.0 million for the period from May 5, 2017 through December 31, 2017, primarily related to a $17.0 million gain in connection with the sale of a third-party midstream entity with whom our natural gas gathering and processing agreements entitled us to a percentage of the proceeds in the event of a sale.

• We recognized a gain on extinguishment of debt of approximately $42.3 million for the year ended December 31, 2016 related to the repurchase of certain of the 2021 Senior Notes and 2022 Senior Notes.

For the Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

A net loss of $540.4 million was recorded for the year ended December 31, 2016, primarily due to impairment charges and loss on commodity derivatives. A net loss of $395.5 million was generated for the year ended December 31, 2015, primarily due to impairment charges partially offset by significant gains on commodity derivatives.

• Oil, natural gas and NGL revenues for 2016 totaled $284.1 million, a decrease of $71.4 million compared with 2015. Production decreased 10.5 Bcfe (approximately 11%), primarily from decreased drilling activities, flooding in East Texas and a temporary production curtailment and planned plant turnaround at our Bairoil properties. The average realized sales price decreased $0.38 per Mcfe primarily due to lower period-to-period commodity prices. Crude oil volumes comprised 28% of total volumes for 2016 compared to 27% for 2015. The unfavorable volume and pricing variance contributed to an approximate $40.6 million decrease and $30.8 million decrease in revenues, respectively.

• Lease operating expense was $126.2 million and $168.2 million for 2016 and 2015, respectively. On a per Mcfe basis, lease operating expense decreased to $1.54 for 2016 from $1.82 for 2015. Reductions in lease operating expenses were a result of our continued reductions in service provider costs and workover activities, field workforce reductions and the Permian Divestiture and Rockies Divestiture, partially offset by the 2015 Beta Acquisition.

• Gathering, processing and transportation expenses were $35.0 million and $34.9 million for 2016 and 2015, respectively. On a per Mcfe basis, gathering, processing and transportation expenses were $0.43 for 2016 compared to $0.38 for 2015 primarily due to increased costs in East Texas.

• Taxes other than income for 2016 totaled $15.5 million, a decrease of $10.3 million compared with 2015 primarily due to a decrease in commodity prices. On a per Mcfe basis, these taxes declined to $0.19 per Mcfe for 2016 from $0.28 per Mcfe for 2015 due to a decrease in commodity prices.

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• DD&A expense for 2016 was $171.6 million compared to $195.8 million for 2015, a $24.2 million decrease primarily due to decreased production volumes, divestitures, and impairments recognized on certain properties over the course of 2016 and 2015, partially offset by incremental DD&A as a result of the 2015 Beta Acquisition. Decreased production volumes caused DD&A expense to decrease by approximately $22.4 million and the change in the DD&A rate between periods caused DD&A expense to decrease by $1.8 million.

• We recognized $183.4 million of impairments during 2016 related to certain properties in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of declining commodity prices and change in future planned development due to liquidity constraints as a result of our reduced borrowing base during the three months ended December 31, 2016. We recognized $616.8 million of impairments during 2015 primarily related to certain properties in East Texas, South Texas, the Permian Basin, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable due to a downward revision of estimated proved reserves as a result of declining commodity prices and updated well performance data. For additional information, see Note 5 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

• General and administrative expenses for 2016 were $63.3 million, which included $10.1 million in reorganizations costs related to the restructuring process, which represents costs directly associated with the Chapter 11 proceedings for advisory and professional fees, $7.4 million of non-cash unit-based compensation expense, $2.1 million in bad debt write-off, $1.5 million of acquisition and divestiture-related costs, and $0.7 million allocated loss on previous corporate office lease. General and administrative expenses for 2015 totaled $56.7 million, which included $10.8 million of non-cash unit-based compensation expense, $1.9 million of acquisition and divestiture-related costs and a $0.8 million allocated loss on a previous corporate office lease.

• Net losses on commodity derivative instruments of $117.1 million were recognized during 2016, consisting of $212.6 million of cash settlements received on expired positions and $230.7 million in cash settlements received on terminated derivatives. These gains were offset by a $560.4 million decrease in the fair value of open positions. Net gains on commodity derivative instruments of $462.9 million were recognized during 2015, consisting of $254.0 million of cash settlements received on expired positions and a $208.9 million increase in the fair value of open positions.

• Interest expense, net totaled $146.0 million during 2016, including amortization and write-offs of deferred financing fees of approximately $22.1 million and accretion and write-off of net discount associated with our senior notes of $13.2 million. Interest expense, net totaled $115.2 million during 2015, including amortization of deferred financing fees of approximately $6.1 million and accretion of net discount associated with our senior notes of $2.4 million. The $30.9 million increase in interest expense was primarily due to $16.9 million for the write-off of the remaining unamortized deferred financing costs, $13.2 million write-off of the remaining discount on the senior notes, and $5.4 million due to the increase in average outstanding borrowings and higher rates under our Predecessor’s revolving credit facility during 2016 compared to 2015 partially offset by decreased period-to-period losses incurred on interest rate swaps of approximately $3.4 million during 2016 compared to 2015.

Average outstanding borrowings under our Predecessor’s revolving credit facility were $746.0 million during 2016 compared to $652.2 million during 2015. For 2016, we had an average of $1.1 billion aggregate principal amount of our senior notes issued and outstanding. For 2015, we had an average of $1.2 billion aggregate principal amount of our senior notes issued and outstanding.

• We recognized a gain on extinguishment of debt of approximately $42.3 million during 2016 related to the repurchase of the 2021 Senior Notes and 2022 Senior Notes. During 2015, we recognized a gain on extinguishment of debt of approximately $0.4 million related to the repurchase of the 2022 Senior Notes.

Adjusted EBITDA

We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash flow from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

• Interest expense, including gains or losses on interest rate derivative contracts;

• Income tax expense;

• Depreciation, depletion and amortization (“DD&A”);

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• Impairment of goodwill and long-lived assets (including oil and natural gas properties);

• Accretion of asset retirement obligations (“AROs”);

• Loss on commodity derivative instruments;

• Cash settlements received on expired commodity derivative instruments;

• Losses on sale of assets and other, net;

• Share/unit-based compensation expenses;

• Exploration costs;

• Acquisition and divestiture related expenses;

• Amortization of gain associated with terminated commodity derivatives;

• Restructuring related costs;

• Reorganization items, net;

• Bad debt expense; and

• Other non-routine items that we deem appropriate.

Less:

• Interest income;

• Income tax benefit;

• Gain on extinguishment of debt

• Gain on expired commodity derivative instruments;

• Cash settlements paid on expired commodity derivative instruments;

• Gains on sale of assets and other, net; and

• Other non-routine items that we deem appropriate.

We are required to comply with certain Adjusted EBITDA-related metrics under our Credit Facility.

We believe that Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.

Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

In addition, management uses Adjusted EBITDA to evaluate actual cash flow, develop existing reserves or acquire additional oil and natural gas properties.

The following tables present our calculation of Adjusted EBITDA as well as a reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.

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Calculation of Adjusted EBITDA

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017			For the Year Ended
	through			through			December 31,			December 31,
	December 31, 2017			May 4, 2017			2016			2015
	(In thousands)			(In thousands)
Net income (loss)	$	1,286		$	(90,955	)	$	(540,398	)	$	(395,491	)
Interest expense, net		15,936			10,243			146,031			115,154
Gain on extinguishment of debt		—			—			(42,337	)		(422	)
Income tax expense (benefit)		(2,176	)		(91	)		173			(2,175	)
DD&A		35,979			37,717			171,629			195,814
Impairment of proved oil and gas properties		—			—			183,437			616,784
Accretion of AROs		4,384			3,407			10,231			7,125
(Gains) losses on commodity derivative instruments		31,609			(23,076	)		117,105			(462,890	)
Cash settlements received (paid) on expired commodity derivative instruments		30,445			15,895			212,566			254,047
Amortization of gain associated with terminated commodity derivatives		—			—			42,236			—
(Gain) loss on sale of properties		—			—			(2,754	)		(2,998	)
Acquisition and divestiture related expenses		609			—			1,451			1,928
Share/Unit-based compensation expense		2,516			3,667			7,351			10,809
Exploration costs		32			16			981			2,317
Insurance recoveries related to environmental remediation		—			—			—			(1,216	)
(Gain) loss on settlement of AROs		181			36			531			1,606
Restructuring related costs		—			7,548			—			—
Reorganization items, net		1,119			88,774			10,069			—
Third-party midstream transaction		(16,979	)		—			—			—
Bad debt expense		—			—			2,050			—
Other		—			57			229			—
Adjusted EBITDA	$	104,941		$	53,238		$	320,581		$	340,392

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017			For the Year Ended
	through			through			December 31,			December 31,
	December 31, 2017			May 4, 2017			2016			2015
	(In thousands)			(In thousands)
Net cash provided by operating activities	$	102,203		$	117,937		$	408,626		$	216,751
Changes in working capital		3,271			(8,963	)		(26,614	)		13,599
Interest expense, net		15,936			10,243			146,031			115,154
Gain (loss) on interest rate swaps		—			—			(1,289	)		(4,674	)
Cash settlements paid (received) on interest rate derivative instruments		—			—			3,944			4,004
Cash settlements received on terminated commodity derivatives		—			(94,146	)		(230,729	)		—
Amortization of gain associated with terminated commodity derivatives		—			—			42,236			—
Amortization and extinguishment of deferred financing fees		(2,093	)		—			(22,106	)		(6,058	)
Accretion and extinguishment of senior notes discount		—			—			(13,185	)		(2,430	)
Acquisition and divestiture related expenses		609			—			1,451			1,928
Income tax expense (benefit) - current portion		30			(17	)		(14	)		59
Exploration costs		32			16			189			239
Plugging and abandonment cost		813			200			1,972			3,036
Environmental expense		—			—			—			(1,216	)
Restructuring related costs		—			7,548			—			—
Reorganization items, net		1,119			20,420			10,069			—
Third-party midstream transaction		(16,979	)		—			—			—
Adjusted EBITDA	$	104,941		$	53,238		$	320,581		$	340,392

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Liquidity and Capital Resources

Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our Predecessor’s revolving credit facility or our Credit Facility, as applicable, and equity and debt capital markets. As we pursue reserve and production growth, we plan to monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our Credit Facility will provide us with the financial flexibility necessary to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2018 development drilling activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. In 2018, we expect our primary funding sources to be cash flows generated by operating activities, available borrowing capacity under our Credit Facility and/or divestitures of assets.

Capital Markets. We do not currently anticipate any near-term capital markets activity, but we will continue to evaluate the availability of public debt and equity for funding potential future growth projects and acquisition activity.

Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 75% of our estimated production from total proved developed producing reserves over a one-to-three year period at any given point of time to satisfy the hedging covenants in our Credit Facility and pursuant to our internal policies. We may, however, from time to time, hedge more or less than this approximate amount. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts. For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of December 31, 2017, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could also result in losses.

Capital Expenditures. Our total capital expenditures were approximately $51.8 million and $9.5 million, for the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017, respectively, which were primarily related to drilling, capital workovers and capital facilities expenditures located in East Texas, South Texas and California.

Government Trust Account. In 2015, the Bureau of Safety and Environmental Enforcement issued a preliminary report that indicated the estimated cost of decommissioning the offshore production facilities associated with our Beta properties in offshore Southern California may further increase. The implementation of this increase is currently on hold and we do not expect resolution of a negotiated decommissioning estimate until 2018. At December 31, 2017, there was approximately $152.3 million in the trust account and $62.0 million in surety bonds.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable as well as the classification of our debt outstanding. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decreases in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.

As of December 31, 2017, we had a working capital balance of $35.9 million primarily due to a current derivative asset balance of $28.5 million partially offset by the timing of accruals, which included accrued lease operating expense of approximately $6.4 million, accrued general and administrative expense of approximately $4.4 million, and accrued capital expenditures of approximately $3.9 million.

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Debt Agreements

Credit Facility. On May 4, 2017, OLLC, as borrower, entered into the Credit Facility with Wells Fargo Bank, National Association, as administrative agent. Pursuant to the Credit Agreement the lenders party thereto agreed to provide OLLC with a $1 billion senior secured reserve-based Credit Facility. Our borrowing base is subject to redetermination on at least a semi-annual basis primarily based on a reserve engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. On November 30, 2017, we entered into the first amendment to our Credit Agreement. The first amendment, among other things, amended the Credit Agreement to reflect the reduction of the borrowing base under the Credit Facility from $475.0 million to $450.0 million, effective as of November 30, 2017, with the borrowing base to be automatically reduced by $2.5 million each month until the next scheduled redetermination. The borrowing base as of December 31, 2017, was approximately $447.5 million.

As of December 31, 2017, we were in compliance with all the financial (interest coverage ratio, current ratio and total leverage ratio) and other covenants associated with our Credit Facility.

As of December 31, 2017, we had approximately $69.1 million of available borrowings under our Credit Facility, net of $2.4 million in letters of credit.

See Note 10 of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015 have been derived from our Consolidated and Combined Financial Statements. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated and Combined Cash Flows included under “Item 8. Financial Statements and Supplementary Data” contained herein.

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017			For the Year Ended
	through			through			December 31,
	December 31, 2017			May 4, 2017			2016			2015
	(In thousands)			(In thousands)
Net cash provided by operating activities	$	102,203		$	117,937		$	408,626		$	216,751
Net cash (used in) investing activities		(53,357	)		(6,496	)		(16,442	)		(337,569	)
Net cash provided by (used in) financing activities		(62,594	)		(106,674	)		(377,410	)		120,447

For the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $102.2 million, $117.9 million and $408.6 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. Production volumes were approximately 177.8 MMcfe/d, 188.2 MMcfe/d and 223.4 MMcfe/d for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. The average realized sales price was $4.79 per Mcfe, $4.67 per Mcfe and $3.47 per Mcfe for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. Lease operating expense was $74.5 million, $35.6 million and $126.2 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. Gathering, processing and transportation expenses were $18.7 million, $10.8 million and $35.0 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively.

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Investing Activities. Net cash used in investing activities for the period from May 5, 2017 through December 31, 2017 was $53.4 million, of which $52.7 million was used for additions to oil and gas properties. Net cash used in investing activities for the period from January 1, 2017 through May 4, 2017 was $6.5 million, of which $6.2 million was used for additions to oil and gas properties. Net cash used in investing activities for the year ended December 31, 2016 was $16.4 million, of which $57.7 million was used for additions to oil and gas properties and $7.9 million used for additions to other property and equipment. This amount was partially offset by $52.7 million in proceeds from the sale of oil and natural gas properties for the year ended December 31, 2016. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and natural gas properties. Additions to restricted investments were $0.5 million, $0.2 million and $8.4 million for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, respectively. See Note 9 of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our restricted investments.

Financing Activities. The Company had net repayments of $54.0 million under the Credit Facility and made $8.2 million in payments to the holders of the Notes, $1.3 million in payments to the Predecessor common unitholders and received a $1.5 million contribution from management in accordance with the Plan for the period from May 5, 2017 through December 31, 2017. The Company had net repayments of $81.7 million under the Predecessor’s revolving credit facility, made $16.4 million in payments to the holders of the Notes and paid $8.6 million in deferred financing costs for the period from January 1, 2017 through May 4, 2017. The Company had net repayments of $324.3 million under the Predecessor’s revolving credit facility for the year ended December 31, 2016. Distributions to partners for the year ended December 31, 2016 were $13.3 million. We repurchased an aggregate principal amount of approximately $85.7 million of the Notes for $41.3 million for the year ended December 31, 2016.

For the year ended December 31, 2016 compared to the year ended December 31, 2015

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities increased by $191.9 million period-over-period. Production decreased 10.5 Bcfe (approximately 11%) and the average realized sales price decreased $0.38 per Mcfe as previously discussed under “—Results of Operations.” During 2016, oil, natural gas and NGL revenues were $284.1 million, a decrease of $71.4 million compared to 2015. Lease operating expense was $126.2 million, a decrease of $42.0 million compared to 2015. Taxes other than income decreased to $15.5 million from $25.8 million during 2015. Cash paid for interest during 2016 was $87.5 million compared to $107.3 million during 2015. Cash settlements on terminated derivatives were $228.6 million during 2016. In 2015, we received cash settlements on terminated derivatives of $47.9 million and we paid $47.9 million in premiums for commodity derivatives. Cash settlements received on expired derivative instruments were $210.7 million during 2016 compared to $250.0 million during 2015.

Investing Activities. Net cash used in investing activities during 2016 was $16.4 million, of which $57.7 million was used for additions to oil and gas properties. This amount was partially offset by $52.7 million in proceeds from the sale of oil and natural gas properties primarily related to the Permian Divestiture and Rockies Divestiture. Cash used in investing activities during 2015 was $337.6 million, of which $100.7 million was used to acquire oil and natural gas properties from third parties and $241.3 million was used for additions to oil and gas properties. We received a post-closing settlement receipt of $9.6 million related to the July 2014 Wyoming acquisition during 2015. See Note 5 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding acquisitions and divestitures.

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our California oil and gas properties. During 2016 and 2015, additions to restricted investments were $8.4 million and $5.7 million, respectively. During 2016, we replaced $4.8 million of restricted investments with $4.8 million of surety bonds related to our decommissioning obligation of the offshore production facilities associated with the Beta properties. See Note 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our restricted investments.

Financing Activities. Distributions to our Predecessor’s partners during 2016 and 2015 were $13.3 million and $163.3 million, respectively. The decrease is primarily due to a decrease in the declared distribution rate and suspension of distributions. We paid $78.4 million to Memorial Resource in connection with the Property Swap in February 2015. Capital contributions received from the previous owners were $1.9 million during 2015.

During 2016, we repurchased an aggregate principal amount of approximately $26.4 million of the 2021 Senior Notes and $14.9 million of the 2022 Senior Notes. During 2015, we repurchased a principal amount of approximately $3.0 million of the 2022 Senior Notes, of which $2.9 million was classified as a financing outflow representing repayment of the original proceeds and $0.3 million classified as an operating inflow.

During 2016, we sold approximately 1.2 million common units under an at-the-market program and generated net proceeds of $1.8 million. During 2015, we repurchased $54.2 million in common units, which represented a repurchase and retirement of 3,641,721 common units under the December 2014 repurchase program. This repurchase program expired in December 2015. See Note 11 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

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We had net repayments of $324.3 million under the Predecessor’s revolving credit facility during 2016. We had net borrowings of $424.0 million under the Predecessor’s revolving credit facility during 2015 that were primarily used to fund a common control acquisition transaction and to fund its drilling program. Deferred financing costs of approximately $1.4 million were incurred during 2016 compared to approximately $0.3 million during 2015.

Capital Requirements

See “— Outlook” for additional information regarding our capital spending program for 2018.

Contractual Obligations

In the table below, we set forth our contractual obligations as of December 31, 2017. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

			Payment or Settlement due by Period
Contractual Obligation	Total		Less than 1 year		1-3 years		4-5 years		Thereafter
	(In thousands)
Credit Facility (1)	$	376,000	$	—	$	—	$	376,000	$	—
Estimated interest payments (2)		62,078		19,101		38,202		4,775		—
Asset retirement obligations (3)		100,173		713		—		—		99,460
CO2 minimum purchase commitment (4)		13,633		4,801		8,832		—		—
Operating leases (5)		14,433		6,155		4,224		2,414		1,640
Midstream services (6)		15,383		3,075		6,158		6,150		—
Total	$	581,700	$	33,845	$	57,416	$	389,339	$	101,100

(1) Represents the scheduled future maturities of principal amount outstanding for the periods indicated. Maturities are shown at original maturity dates assuming no acceleration. See Note 10 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for information regarding our Credit Facility.

(2) Estimated interest payments are based on the principal amount outstanding under our Credit Facility at December 31, 2017. In calculating these amounts, we applied the weighted-average interest rate for the period from May 5, 2017 through December 31, 2017 associated with such debt. See Note 10 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for the weighted-average variable interest rate charged during 2017 under our Credit Facility. Maturities are shown at original maturity dates assuming no acceleration.

(3) Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2017 balance sheet. See Note 8 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for additional information regarding our asset retirement obligations.

(4) Represents a firm agreement to purchase CO₂ volumes related to our Bairoil properties in Wyoming.

(5) Primarily represents leases for office space as well as equipment rentals and offshore Southern California right-of-way use. See Note 15 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for information regarding our operating leases.

(6) Represents processing fees associated with a minimum volume commitment related to certain of our properties located in East Texas.

Off–Balance Sheet Arrangements

As of December 31, 2017, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 4 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the prices that we receive for our oil, natural gas and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices we receive. It has been our practice to enter into fixed price swaps and costless collars only with lenders and their affiliates under our Predecessor’s revolving credit facility and our Credit Facility.

In January 2017, in connection with our restructuring efforts, we monetized $94.1 million in commodity hedges and used a portion of the proceeds to repay outstanding borrowings under our Predecessor’s revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes.

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In December 2016, in connection with our restructuring efforts, we monetized approximately $191.4 million in commodity hedges and settled $2.1 million in interest rate swaps prior to the Petition Date and used a significant portion of the proceeds to reduce amounts outstanding under our Predecessor’s revolving credit facility. During the period from April 2016 through June 2016, we monetized approximately $39.3 million in commodity hedges and utilized the proceeds to buy back senior notes.

Swaps. In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.

Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX, ICE, or regional quoted prices, and pay the excess, if any, of the reference price over the contract ceiling price. Collars are typically exercised in cash on a monthly basis only when the reference price is outside of floor and ceiling prices (the collar), otherwise they expire. As of December 31, 2017, we did not have any outstanding collars.

The following table summarizes our derivative contracts as of December 31, 2017 and the average prices at which the production will be hedged:

	2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		1,102,000		300,000
Weighted-average fixed price	$	3.91	$	2.91
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		152,000		110,000
Weighted-average fixed price	$	71.31	$	51.34
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		65,700		—
Weighted-average fixed price	$	24.13	$	—

The following table summarizes our derivative contracts as of December 31, 2016 and the average prices at which the production was hedged:

	2017		2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		1,890,000		1,740,000		1,000,000
Weighted-average fixed price	$	3.86	$	3.83	$	3.47
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		184,500		182,000		70,000
Weighted-average fixed price	$	84.29	$	83.44	$	86.84
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		43,300		—		—
Weighted-average fixed price	$	37.55	$	—	$	—

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. During December 2016, in connection with our restructuring efforts, we elected to terminate the interest rate swaps associated with our Predecessor’s revolving credit facility and in the aggregate paid our counterparties approximately $2.1 million. The Company did not have any interest rate swaps at December 31, 2017 and 2016.

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Counterparty and Customer Credit Risk

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. Some of the lenders, or certain of their affiliates, under our Credit Facility are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2017, after taking into effect netting arrangements, we had no counterparty exposure related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $26.5 million against amounts outstanding under our Credit Facility at December 31, 2017.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated and Combined Financial Statements, together with the report of our independent registered public accounting firm, begin on page F-1 of this annual report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of the Company, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this annual report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of the Company, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon this evaluation, the principal executive officer and principal financial officer of the Company have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2017.

Management’s Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Under the supervision and with the participation of the Company’s management, including the principal executive officer and principal financial officer of the Company, the Company assessed the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this assessment, the Company’s management, including its principal executive and financial officers, concluded that the Company’s internal control over financial reporting was effective as of December 31, 2017 based on the criteria set forth under the COSO Framework.

KPMG LLP, the independent registered public accounting firm who audited the Company’s Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” in this annual report, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017, is contained herein under the heading “Report of Independent Registered Public Accounting Firm.”

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Changes in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as exhibits 31.1 and 31.2, respectively, to this annual report.

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Report of Independent Registered Public Accounting Firm

The Stockholders and Board of Directors

Amplify Energy Corp.:

Opinion on Internal Control Over Financial Reporting

We have audited Amplify Energy Corp. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2017 (Successor) and 2016 (Predecessor), the related consolidated statements of operations, equity, and cash flows for the period May 5, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through May 4, 2017, the year ended December 31, 2016 and the related consolidated and combined statements of operations, equity, and cash flows for the year ended 2015 (Predecessor) and the related notes (collectively, the consolidated and combined financial statements), and our report dated March 12, 2018 expressed an unqualified opinion on those consolidated and combined financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Houston, Texas

March 12, 2018

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ITEM 9B. OTHER INFORMATION

None

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board Leadership Structure and Role in Risk Oversight

Leadership of our board of directors is vested in a Chairman of the board of directors. David H. Proman serves as the Director and Chairman of the board of directors the Company. We do not have a policy requiring either that the positions of the Chairman of the board of directors and the Chief Executive Officer, be separate or that they be occupied by the same individual. The board of directors believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances.

The management of enterprise-level risk may be defined as the process of identifying, managing and monitoring events that present opportunities and risks with respect to the creation of value for our stockholders. The board of directors has delegated to management the primary responsibility for enterprise-level risk management, while the board of directors has retained responsibility for oversight of management in that regard. Our executive officers offer an enterprise-level risk assessment to the board of directors at least once every year.

Directors and Executive Officers

The following table sets forth certain information regarding the current directors and executive officers of the Company as of March 1, 2018.

Name	Age	Position with the Company
William J. Scarff	62	President, Chief Executive Officer and Director
Christopher S. Cooper	50	Senior Vice President and Chief Operating Officer
Robert L. Stillwell, Jr.	40	Senior Vice President and Chief Financial Officer
Eric M. Willis	39	Vice President and General Counsel
Richard P. Smiley	59	Vice President, Onshore Operations
Matthew J. Hoss	35	Vice President and Chief Accounting Officer
David H. Proman	35	Director and Chairman
Christopher W. Hamm	50	Director
P. Michael Highum	67	Director
Evan S. Lederman	38	Director
Edward A. Scoggins, Jr.	38	Director

Our directors hold office until the earlier of their respective death, resignation, removal or disqualification or until their respective successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors and executive officers. Certain of our directors and executive officers served as directors and officers of Memorial Production Partners GP, LLC, the general partner of our Predecessor, prior to the Petition Date and during the Chapter 11 proceedings.

William J. Scarff has served as our President and Chief Executive Officer since our inception in May 2017. From September 2016 to May 2017, he served as Chief Executive Officer of Memorial Production Partners GP, LLC, the general partner of our Predecessor and from January 2014 to September 2016 as President of our Predecessor’s general partner. Mr. Scarff also served as President of Memorial Resource from January 2014 to January 2016. Previously, Mr. Scarff served as President of MRD LLC from January 2014 to June 2014. From 2000 through January 2014, Mr. Scarff served as President and Chief Executive Officer of several private exploration and production companies sponsored by NGP. From October 2010 until January 2014, Mr. Scarff was President and Chief Executive Officer of Propel Energy, LLC. Prior to that, he was President and Chief Executive Officer of Seismic Ventures, Inc. from 2006 to 2009. From 2005 to 2014, Mr. Scarff was President and Chief Executive Officer of Proton Operating Company, LLC and from 1999 to 2005, he was President and Chief Executive Officer of Proton Energy, LLC and its affiliates. From 1978 to 1999, Mr. Scarff held a variety of positions of increasing responsibility in Marathon Oil Company, Anadarko Production Company, Burlington Resources, Texas Meridian Resource Corporation and Hilcorp Energy Company.

The board believes Mr. Scarff’s extensive executive experience with oil and natural gas companies brings valuable strategic, managerial and analytical skills to the board of directors.

Christopher S. Cooper has served as our Senior Vice President and Chief Operating Officer since our inception in May 2017. From November 2014 to May 2017, Mr. Cooper served as Senior Vice President and Chief Operating Officer of Memorial Production Partners GP, LLC, the general partner of our Predecessor. Previously, he served in a variety of operational, technical and strategic planning positions with Marathon Oil Company since 1990. From August 2013 until November 2014, Mr. Cooper served as Director, Global Projects. From November 2011 until August 2013, he served as Director, Financial Planning/Operations. From July 2009 until November 2011, Mr. Cooper served as Asset Manager/Regional Vice President, Mid-Continent, and from May 2007 until July 2009, he served as Asset Manager, Powder River Basin.

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Robert L. Stillwell, Jr. has served as our Senior Vice President and Chief Financial Officer since our inception in May 2017. From January 2015 to May 2017, Mr. Stillwell served as Senior Vice President and Chief Financial Officer of Memorial Production Partners GP, LLC, the general partner of our Predecessor. From July 2014 to January 2015, he served as Vice President - Finance of our Predecessor’s general partner. Previously, he served as Treasurer of MRD LLC from June 2012 to June 2014. From January 2011 to June 2012, Mr. Stillwell served as an investment banker at Citigroup in the Global Energy Group. From June 2010 to December 2010 and from July 2007 to June 2010, he worked in investment banking with UBS and Scotia Waterous, respectively. Mr. Stillwell began his career in the corporate finance group of EXCO Resources, Inc.

Eric M. Willis has served as our Vice President and General Counsel since December 2017. From April 2015 to December 2017, Mr. Willis was a partner in the capital markets practice group at Kirkland & Ellis LLP in Houston, Texas, representing oil and gas clients. Prior to joining Kirkland & Ellis, he practiced corporate and securities law from September 2008 to April 2015 at Latham & Watkins LLP in Houston, Texas and Orange County, California.

Richard P. Smiley has served as our Vice President of Operations – Onshore since our inception in May 2017. He previously served at Memorial Production Partners GP, LLC, the general partner of our Predecessor, as Vice President of Operations – Onshore from March 2016 to May 2017, as Vice President of Operations – Southern Region from August 2015 through February 2016 and as Director, Operations – Northern Region from November 2014 to July 2015. Previously, he was Vice President of Operations at CL&F Resources LP from February 2014 to November 2014. From December 2011 to January 2014, Mr. Smiley served as Vice President of Operations at Propel Energy, LLC. From June 2010 to November 2011 he held the position of Operations Manager at Quantum Resources Management, LLC. Mr. Smiley began his career with El Paso Exploration Company in 1980 and held various engineering, operations and management with multiple companies, including Burlington Resources, Comstock, Bois d’Arc and Stone Energy, throughout the Central United States, both onshore and in the Gulf of Mexico. He has a Petroleum Engineering Degree from Colorado School of Mines.

Matthew J. Hoss has served as our Vice President and Chief Accounting Officer since August 2017 and as our Vice President, Accounting from our inception to July 2017. Previously, Mr. Hoss served as Vice President, Accounting of Memorial Production Partners GP, LLC, the general partner of our Predecessor, from May 2016 to May 2017. He served as Controller of Memorial Resource from January 2015 to April 2016, Director, Accounting of Memorial Resource from July 2014 to December 2014, Director, Accounting of MRD LLC from January 2014 to June 2014 and Manager, Special Projects of MRD LLC from May 2012 to December 2013. Prior to joining MRD LLC, Mr. Hoss held various positions from September 2006 to May 2012 in the transaction services and assurance practices at PricewaterhouseCoopers LLP in Houston, Texas, primarily serving energy clients. Mr. Hoss is a Certified Public Accountant.

David H. Proman has served as our Chairman and a member of our board of directors since our inception in May 2017. Mr. Proman joined Fir Tree Partners in 2010 and is a Managing Director, Co-Head of Restructuring and a Partner on the Investment team. Mr. Proman focuses on the funds’ distressed credit investment strategies, most notably co-managing the firm’s structured mortgage credit and energy restructuring initiatives. Mr. Proman has 13 years of investment experience in structured and corporate debt investing. Prior to joining Fir Tree Partners, Mr. Proman helped manage the corporate and structured mortgage credit investments at Kore Advisors, a fixed income investment fund. Mr. Proman also previously served, in his capacity as a Fir Tree Partners employee, as a member of the board of directors of Eco-Stim Energy Solutions, Inc. Mr. Proman received a B.A. in Economics from the University of Virginia.

The board believes Mr. Proman’s extensive investment and restructuring experience in the energy industry brings valuable strategic and analytical skills to the board of directors.

Christopher W. Hamm has served as a member of our board of directors since our inception in May 2017. Mr. Hamm is a 26 -year veteran of the investment management industry and CEO of AXYS CAPITAL, an SEC registered private investment fund manager he founded in 2009. In 1998, Mr. Hamm founded Memorial Investment Advisors, a registered investment advisor, and Memorial Funds, an institutional multi-fund registered investment company, where he served as Chairman of the Board of Trustees, and developed Millennium Funds, an alternative investment private fund complex. Prior to founding his own firms, Mr. Hamm served as Executive Director – Institutional Services at CIBC Oppenheimer, Senior Vice President – Capital Markets at PaineWebber, and Vice President – Taxable Fixed Income at Howard Weil Labouisse & Friederichs.

The board believes Mr. Hamm’s considerable experience in the investment advisory industry brings substantial investment management skills to the board of directors.

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P. Michael Highum hasserved as a member of our board of directors since our inception in May 2017. Mr. Highum previously served as a member of the board of directors of Memorial Production Partners GP, LLC, the general partner of our Predecessor, from March 2012 until May 2017. Subsequent to his retirement in 2001, he has been primarily involved in managing his private investments. From 2002 to 2006, Mr. Highum served as an advisor to Fidelity Investments, where he helped establish and develop FIML Natural Resources LLC, an oil and gas exploration and production company. He co-founded HS & Associates in 1978, which was the predecessor to the NYSE-listed HS Resources, Inc., an independent oil and gas exploration and production company (later sold to Kerr McGee Corporation in 2001), where he served as President and Director. From 1995 to 2001, Mr. Highum served as a Director (and President in 1999) of the Colorado Oil and Gas Association. Prior to HS & Associates, Mr. Highum practiced corporate law in the San Francisco office of Pillsbury, Madison & Sutro, LLP.

The board believes that Mr. Highum’s considerable executive management and energy investment experience bring substantial investment management skills to the board of directors.

Evan S. Lederman has served as a member of our board of directors since our inception in May 2017. Mr. Lederman serves as a Managing Director, Co-Head of Restructuring and a Partner on the Investment Team at Fir Tree Partners. Mr. Lederman focuses on the funds’ distressed credit and special situation investment strategies, including co-managing its energy restructuring initiatives. Prior to joining Fir Tree Partners in 2011, Mr. Lederman worked in the Business Finance and Restructuring groups at Weil, Gotshal & Manges LLP and Cravath, Swaine & Moore LLP. In addition to Amplify Energy, Mr. Lederman also currently serves, in his capacity as a Fir Tree Partners employee, as a member of the boards of directors of Linn Energy, Inc. (Chairman), Ultra Petroleum Corp., New Emerald Energy LLC, and Deer Finance, LLC. Mr. Lederman received a J.D. degree with honors from New York University School of Law and a B.A., magna cum laude, from New York University.

The board believes that Mr. Lederman’s extensive investment and restructuring experience in the energy industry, as well as his considerable experience as a member of the boards of exploration and production companies, bring valuable strategic and analytical skills to the board of directors.

Edward A. Scoggins, Jr. has served as a member of our board of directors since our inception in May 2017. Mr. Scoggins co-founded Millennial Energy Partners in 2012, and currently serves as Managing Partner. Under his leadership, the firm has secured private equity capital in excess of $300 million and directly invested in oil and gas assets through eight investment vehicles. Prior to Millennial, from 2008 to 2012, Mr. Scoggins led BG Group plc’s commercial and technical teams on oil and gas investments in the Haynesville shale, the Marcellus shale, British Columbia, Chile, Equatorial Guinea and Trinidad and Tobago. Prior to joining BG Group plc, Mr. Scoggins served as Strategic Planning Manager and Community and Public Relations Manager with Marathon Oil Company from 2005 to 2008. Mr. Scoggins began his career with Bechtel Corporation as Project Controls Engineer in Equatorial Guinea, West Africa from 2004 to 2005. In addition to Amplify Energy, Mr. Scoggins also currently serves as a member of the board of directors of Ultra Petroleum Corp. He received his bachelor’s degree in Economics and History from Vanderbilt University and earned his Master of Science in Foreign Service (MSFS) degree with a concentration in business and finance from Georgetown University.

The board believes that Mr. Scoggins’ considerable investment and commercial experience in the energy industry brings valuable strategic and investment skills to the board of directors.

Composition of the Board of Directors

Our board of directors consists of six members. The board of directors holds regular and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board of directors from time to time. Special meetings of the board of directors or meetings of any committee thereof may be held at the request of the Chairman of the board of directors or a majority of the board of directors (or a majority of the members of such committee) upon at least two days (if the meeting is to be held in person) or 24 hours (if the meeting is to be held telephonically) prior oral or written notice to the other members of the board or committee or upon such shorter notice as may be approved by the directors or members of such committee. A quorum for a regular or special meeting will exist when a majority of the members are participating in the meeting either in person or by telephone conference. Any action required or permitted to be taken at a board meeting may be taken without a meeting if such action is evidenced in writing and signed by all of the members of the board of directors.

Board Nominations¶

Prior to our emergence from bankruptcy, our Predecessor’s partnership agreement provided that nominations of persons for election to the board of directors of our Predecessor’s general partner could be made at an annual meeting of our Predecessor’s limited partners only pursuant to our Predecessor’s general partner’s notice of the meeting, (1) by or at the direction of a majority of the directors on our Predecessor’s board of directors, or (2) by any limited partner or group of limited partners of our Predecessor that held or beneficially owned, and continuously held or beneficially owned without interruption for the prior 36 months, at least 3% of our Predecessor’s outstanding units; provided that such limited partner, or each limited partner in such group, was a record holder at the time the notice provided for in our Predecessor’s partnership agreement was delivered to our Predecessor’s general partner and complied with the notice procedures set forth in our Predecessor’s partnership agreement.

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Following our emergence from bankruptcy, we adopted our amended and restated bylaws, which set forth procedures for submitting recommendations for candidates to the board of directors. You are also advised to review our amended and restated bylaws, which contain additional requirements about advance notice of stockholder proposals and director nominations.

Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of the board of directors, all of our independent directors intend to meet in an executive session without participation by management or non-independent directors. Shareholders or interested parties may communicate directly with the board of directors, any committee of the board of directors, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: c/o Secretary, Amplify Energy Corp., 500 Dallas Street, Suite 1600, Houston, Texas 77002. Communications are distributed to the board of directors, committee of the board of directors, or director as appropriate, depending on the facts and circumstances outlined in the communication. Commercial solicitations or communications will not be forwarded.

Director Independence

Our common stock is quoted for trading on OTCQX. Pursuant to OTCQX rules, we are not required to have a majority of independent directors on our board of directors. We are, however, required to have at least two independent members of our board of directors and a majority independent audit committee. The board of directors has determined that, under OTCQX rules, Messrs. Hamm, Highum, Lederman, Proman and Scoggins are independent directors, based on information provided by the directors.

Committees of the Board of Directors

In connection with our emergence from bankruptcy, the board of directors established an audit committee and a compensation committee. The audit committee held two meetings in 2017 and the compensation committee held two meetings in 2017.

Pursuant to OTCQX rules, we are not required to have a nominating committee of the board of directors.

Audit Committee

The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and Company policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof, and pre-approves any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee. The charter for the audit committee is available within the “Corporate Governance” section of our website at http://investor.amplifyenergy.com/corporate-governance.cfm. The information contained on, or connected to, our website is not incorporated by reference into this annual report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Messrs. Hamm, Highum, Lederman, Proman, Scarff and Scoggins currently serve on the audit committee, and Mr. Scoggins serves as the chairman. Pursuant to OTCQX rules, we are required to have a majority independent audit committee. Mr. Scarff, our President and Chief Executive Officer, is not considered independent under OTCQX rules.

The board of directors has determined that Mr. Scoggins is an “audit committee financial expert” as defined under SEC rules.

Compensation Committee

The compensation committee assists the board of directors in its oversight responsibilities with respect to the management of risks arising from our compensation policies and programs. The compensation committee reviews and fixes the salary and other compensation of the Chief Executive Officer and the other executive officers of the Company, including administering the MIP. The charter for the compensation committee is available within the “Corporate Governance” section of our website at http://investor.amplifyenergy.com/corporate-governance.cfm. The information contained on, or connected to, our website is not incorporated by reference into this annual report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Messrs. Hamm, Highum, Lederman, Proman, Scarff and Scoggins currently serve on the compensation committee, and Mr. Hamm serves as the chairman. Pursuant to OTCQX rules, we are not required to have an independent compensation committee. Mr. Scarff, our President and Chief Executive Officer, is not considered independent under OTCQX rules.

Meetings and Other Information

The board of directors meets regularly to review significant developments affecting us and to act on matters requiring its approval. The board of directors held 31 meetings in 2017. None of the directors attended fewer than 75% of the aggregate number of meetings of the board of directors and committees of the board of directors on which the director served.

We believe that there are benefits to having members of the board of directors attend annual meetings, and we will strongly encourage all of the directors to attend the annual meetings; however, attendance is not mandatory.

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Section 16(a) Beneficial Ownership Reporting Compliance

We are not subject to the requirements of Section 16(a) of the Exchange Act.

Corporate Governance

The board of directors has adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of the Company and its affiliates. The Code of Business Conduct and Ethics includes provisions specifically addressed to the Company’s senior financial officers including the chief executive officer, chief financial officer or vice president of finance, chief accounting officer, controller, treasurer and all other persons performing similar functions on behalf of the Company.

We make available free of charge, within the “Corporate Governance” section of our website at http://investor.amplifyenergy.com/corporate-governance.cfm, and in print to any unitholder who so requests, the Code of Business Conduct and Ethics and the Corporate Governance Guidelines. Requests for print copies may be directed to Investor Relations at IR@amplifyenergy.com or to Investor Relations, Amplify Energy Corp., 500 Dallas Street, Suite 1600, Houston, Texas 77002 or made by telephone at (713) 490-8900. We intend to post on our website all waivers of or amendments to Code of Business Conduct and Ethics that are required to be disclosed by Form 8-K. The information contained on, or connected to, our website is not incorporated by reference into this annual report and should not be considered part of this or any other report that we file with or furnish to the SEC.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

This compensation discussion and analysis provides an overview of the 2017 executive compensation program for our named executive officers (“NEOs”) identified below.

Name	Principal Position
William J. Scarff	President and Chief Executive Officer
Christopher S. Cooper	Senior Vice President and Chief Operating Officer
Robert L. Stillwell, Jr.	Senior Vice President and Chief Financial Officer
Richard P. Smiley	Vice President, Onshore Operations
Matthew J. Hoss	Vice President and Chief Accounting Officer

Our Compensation Philosophy

The Company employs a compensation philosophy that emphasizes pay-for-performance based on a combination of the Company’s performance and the individual’s impact on the Company’s performance and placing the majority of each officer’s compensation at risk. We believe this pay-for-performance approach generally aligns the interests of executive officers who provide services to us with that of our stockholders, and at the same time enables us to maintain a lower level of base salary overhead in the event our operating and financial performance fails to meet expectations. Our Company’s executive compensation is designed to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, including the difficult near-term challenges associated with our emergence from bankruptcy on May 4, 2017, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our stockholders, and to reward success in reaching such goals.

Compensation Setting Process

Prior to Emergence. Prior to our emergence from bankruptcy, the board of directors of the Predecessor was responsible for approving and evaluating our director and executive officer compensation, plans, policies and programs for the 2017 fiscal year, including the base salaries for our executive officers and elements of our 2017 annual incentive program, such as the Key Employee Incentive Program described below under “Elements of Executive Compensation — Cash Incentive Awards.”  

The board of directors used several different tools and resources in reviewing elements of executive compensation and making compensation decisions, including the compensation consultant noted below. The board of directors considered input from our president and chief executive officer (“CEO”) in making determinations regarding the executive compensation program and the individual compensation of each executive officer, other than our CEO. Our CEO and management also provided information to the board of directors regarding company performance for the determination by the board of directors of annual bonuses, although our CEO made no recommendations regarding, and did not participate in discussions about, his own compensation. In addition, in connection with the Chapter 11 proceedings, the board of directors considered input on compensation matters from the holders of our Notes. The board of directors made the final determination of NEO compensation, including base salary determinations and the performance measures under our Key Employee Incentive Plan (described below), subject to the approval of the Bankruptcy Court, taking into account this input and these recommendations.  

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During 2016, the Company, at the direction of the board of directors, engaged Pearl Meyer & Partners, LLC (“Pearl Meyer”) as the Company’s independent compensation consultant to provide recommendations regarding our executive officer compensation arrangements for the 2017 fiscal year. Pearl Meyer reported directly to the board of directors and with the consent of the board of directors, coordinated and gathered information with which to advise the board of directors from members of management. Pearl Meyer assisted the board of directors with its review of the Company’s executive and director compensation programs including, without limitation: (i) recommending the most appropriate peer group, (ii) examining competitive levels of base salary, annual incentives, total cash compensation, long-term incentives, and total direct compensation of specified executive officers against the chosen peer group, (iii) comparing the compensation of the Company’s executive team to market data to determine current posture relative to the competitive market, (iv) analyzing how peer companies effectively deliver compensation to their executive officers in terms of overall mix and program design, (v) developing initial recommendations as to the amount and form of compensation to be paid to the executive officers, (vi) developing initial recommendations as to the design/construct of the Company’s go-forward annual incentive (bonus) and long-term incentive programs, including our Key Employee Incentive Plan and the Key Employee Retention Plan (described below), and (vii) assisting in the implementation of the short- and long-term incentive programs, including addressing any ongoing concerns. The peer group used by the board of directors in making 2016 compensation decisions consisted of the following companies: Whiting Petroleum Corp.; SM Energy Company; Denbury Resources Inc.; EP Energy Corporation; Energen Corp.; Oasis Petroleum Inc.; Breitburn Energy Partners LP; Laredo Petroleum, Inc.; Rice Energy Inc.; Stone Energy Corp.; Carrizo Oil & Gas Inc.; Vanguard Natural Resources, LLC; PDC Energy, Inc.; Legacy Reserves LP; EXCO Resources Inc.; Parsley Energy, Inc.; Bonanza Creek Energy, Inc.; Comstock Resources Inc.; Bill Barrett Corp.; and Northern Oil and Gas, Inc. This peer group was selected in order to reflect the range of market capitalization of the Predecessor over the several years prior to 2016 and similar business lines to the Predecessor (i.e., independent oil and gas exploration and production companies).

Following Emergence. Following our emergence from bankruptcy, our board of directors assumed primary responsibility for reviewing and evaluating our director and executive officer compensation plans, policies and programs for the 2017 fiscal year, including the terms of the Emergence Awards described below under “Elements of Executive Compensation — Long Term Incentive Compensation,” evaluating achievement of the performance metrics under the Key Employee Incentive Plan, and payment of annual cash incentive awards in respect of the 2017 fiscal year. Beginning in June 2017, the board of directors formed a compensation committee, consisting of all members of the board of directors, which is responsible for reviewing, evaluating, and approving the agreements, plans, policies, and programs of the Company to compensate our executive officers and directors, and overseeing our employee benefit plans, policies and programs to compensate our executive officers and non-executive employees. The compensation committee reviews and discusses all recommendations prior to approval, then submits all recommendations to the board of directors for approval.

The compensation committee relied on several resources in reviewing elements of executive compensation and making compensation decisions following our emergence from bankruptcy, including compensation levels and performance objectives established prior to 2017 based on the Pearl Meyer analysis, and input from our CEO in making determinations regarding the executive compensation program and the individual compensation of each executive officer other than our CEO. Although our CEO is a member of the compensation committee, consistent with the compensation setting process prior to our emergence from bankruptcy, he makes no recommendations regarding, and does not participate in discussions about, his own compensation. The compensation committee did not retain an independent compensation consultant for the 2017 fiscal year, or rely on a benchmarking analysis as a reference point or framework for compensation decisions in 2017.  

Elements of Executive Compensation

There are three primary elements of compensation that are used in our executive compensation program: base salary, cash bonus and long-term equity incentive awards. Cash bonuses and equity incentives (as opposed to base salary) represent the performance driven elements of the compensation program. These elements are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals’ cash bonuses awarded in respect of a performance period reflects each individuals relative contribution to achieving or exceeding annual goals, and the determination of specific individuals’ long-term incentive awards is based on the individual’s expected contribution in respect of longer term performance objectives.

Base Salary. We believe the base salaries for our named executive officers are generally competitive within the market, but are moderate relative to base salaries paid by companies with which we compete for similar executive talent across the broad spectrum of the energy industry. We review the base salaries on an annual basis and may make adjustments as necessary to maintain a competitive executive compensation structure. As part of our review, we may examine the compensation of executive officers in similar positions with similar responsibilities at peer companies identified by us or the board of directors or at companies within the oil and gas industry with which we generally compete for executive talent. We did not make any adjustments to the base salaries of our named executive officers for the 2017 fiscal year.

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Cash Incentive Awards. Cash incentive awards are discretionary and may be determined based on financial and/or individual performance. We review bonus awards for our named executive officers annually to determine award payments for the most recently completed fiscal year, as well as to establish award opportunities for the next fiscal year. At the end of each fiscal year, we meet with each executive officer to discuss our performance goals for the upcoming fiscal year and what each executive officer is expected to contribute to help us achieve those performance goals. The determination of specific individuals’ actual cash bonus payout will reflect their relative contribution to achieving or exceeding annual goals.

The board of directors considers and takes into account several factors in determining the discretionary bonus awards such as production, operating expenses, safety/environmental, general and administrative expenses and management and strategic initiatives. For the 2017 fiscal year, our annual bonus program for our named executive officers consisted of the Key Employee Incentive Plan (“KEIP”).

The KEIP is a program that was established by the board of directors of our Predecessor prior to our emergence from bankruptcy, and measures achievement of performance objectives related to:

• Total OSHA reportable injuries, weighted as 20% of the total bonus payment;

• Average daily production, weighted at 40% of the total bonus payment; and

• Lease operating expenses, weighted at 40% of the total bonus payment.

These performance objectives were selected in order to motivate key employees, including our named executive officers, and reward them for successfully executing our business strategies as measured against quantitative operational and financial measures for 2017.

Quarterly threshold, target, and maximum performance levels for each performance objective were established by the board of directors prior to the 2017 fiscal year, and set at challenging levels that were both consistent with our long-term goals and intended to incentivize and reward superior performance. If threshold performance level was not achieved with respect to any of the performance objectives in a quarter, no bonus amount was payable in respect of that performance objective for that quarter. There are no individual or personal performance objectives applicable to awards under the KEIP.

Cash incentive awards under the KEIP were paid on a quarterly basis for the first and second quarters of 2017, and in February 2018 for the third and fourth quarters of 2017. The board of directors certified achievement of the performance objectives for the first quarter of 2017, and the compensation committee certified achievement of the performance objectives for the remaining quarters. All performance objectives were achieved, on average, at 130% of target performance levels for the first quarter of 2017, but in connection with our emergence from bankruptcy and in order to facilitate the successful reorganization of the Company, each participant in the KEIP program, including our NEOs, agreed to waive payment of a significant portion of the payment to which he would otherwise have been entitled to under the KEIP, including waiver of $400,000 by Mr. Scarff, $161,111 by Mr. Cooper, $260,000 by Mr. Stillwell, $80,556 by Mr. Smiley, and $60,417 by Mr. Hoss. All performance objectives were achieved, on average, at 130% of target performance levels for the second quarter of 2017, and performance objectives were achieved, on average, at 70% of target performance levels for the third and fourth quarters of 2017.

For the 2017 fiscal year, the aggregate target award for each NEO under the KEIP, and the aggregate cash incentive award paid to each NEO under the KEIP (after waiver of the bonus amounts described above) was as follows:

	Total Target KEIP		Total KEIP Payment
Name	Incentive Bonus		for 2017 Fiscal Year
William J. Scarff		1,400,000		1,000,000
Christopher S. Cooper		800,000		638,889
Robert L. Stillwell, Jr.		800,000		540,000
Richard P. Smiley		400,000		319,944
Matthew J. Hoss		300,000		239,583

Long Term Incentive Compensation. Prior to our emergence from bankruptcy, our NEOs received awards of restricted units and phantom units under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”). Each award of restricted units consisted of common units of Memorial Production Partners LP, which were subject to vesting in equal installments over a three-year period. Each award of phantom units represented the right, upon vesting, to receive a cash payment equal to the value of a common unit of our Predecessor. Awards of phantom units were subject to vesting in equal installments over a three-year period. In connection with our emergence from bankruptcy, all restricted units vested in accordance with their terms, and all phantom units were cancelled in exchange for the payments described in the table titled “Option Exercises and Stock Vested” below (or in the case of Mr. Scarff, cancelled without consideration).  

In connection with our emergence from bankruptcy, the Company adopted the Amplify Energy Corp. Management Incentive Plan (the “MIP”) for key personnel who perform services for us. The purpose of awards under our MIP is to align the interests of eligible employees with the interests of our stockholders by providing long-term incentive compensation opportunities tied to the performance of the company.

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Each of our NEOs is eligible to participate in our MIP. Our MIP allows for the grant of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units (“RSUs”), stock appreciation rights, performance awards, stock awards and other incentive awards. A maximum of 2,322,404 shares of the Company’s common stock are reserved for issuance under the MIP. As of December 31, 2017, 1,122,214 of those common shares remained available for future awards. Shares of common stock subject to awards that are cancelled, expired, forfeited or otherwise terminated without delivery of the underlying share will be available for delivery pursuant to other awards.

Emergence Awards. In connection with our emergence from bankruptcy, our NEOs were granted awards of RSUs and stock options under the MIP (“Emergence Awards”). The Emergence Awards were included as components of the Plan approved by the Bankruptcy Court, and included the following awards granted to our NEOs:

	AggregateNumber		AggregateNumber of
Name	of RSUs (#)		Stock Options (#)
William J. Scarff		125,854		125,854
Christopher S. Cooper		88,000		88,000
Robert L. Stillwell, Jr.		66,000		66,000
Richard P. Smiley		28,600		28,600
Matthew J. Hoss		17,500		17,500

The Emergence Awards generally vest in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant, so long as the award recipient remains in continuous service with the Company and its affiliates through the applicable vesting date. If a participant’s employment is terminated by us following the participant’s disability, or due to the participant’s death, any unvested RSUs will become vested and the portion of the stock options granted under the Emergence Awards that would have become vested on the next annual vesting date will become vested as of the date of termination. The Emergence Awards are also subject to customary terms regarding transferability, dividend equivalent rights, exercisability, and, in the case of our NEOs, require the NEO to enter into the Company’s standard restrictive covenant agreement, which includes obligations relating to confidentiality, non-solicitation of employees, consultants and customers, and non-competition.

Under the terms of the MIP, the exercise price applicable to any stock option must be equal to or greater than the fair market value of a share of common stock on the date of grant, calculated as the closing price for our shares on the date of grant. The exercise price of the stock options granted as Emergence Awards was equal to $21.58, which represents a significant premium over the price of a share of common stock at the time of our emergence from bankruptcy ($13.77). This exercise price was selected to reward our NEOs only following the creation of outstanding share price growth for our shareholders.

In general, pursuant to the MIP Severance Agreements described below under “— MIP Severance Agreements”, any portion of the Emergence Awards granted to an NEO that is unvested on the date of the participant’s termination of employment by the Company (with or without “cause”) or the participant’s resignation (with or without “good reason”) is forfeited. However, if the employment of the NEO is terminated either by the Company (or an affiliate) without “cause” or by the award recipient for “good reason” (as such terms are defined in the applicable award agreement for the Emergence Award) at any time following the occurrence of a change of control, all unvested RSUs and stock options subject to the Emergence Award granted to the executive will become immediately vested in full. In addition, if an NEO’s employment is terminated following the NEO’s death or disability, the portion of the stock options granted under the Emergence Awards which would vest on the next scheduled vesting date will become vested and exercisable on the termination date, and any unvested RSUs become vested. In the event that, at the time of an NEO’s termination of employment without cause or with good reason, our shares are not traded on a national securities exchange (and for this purpose, trading on an over-the-counter system does not constitute a national securities exchange) the NEO may require us to purchase all shares acquired pursuant to the Emergence Award at a price equal to the then-current fair market value of the shares.  

Other MIP Awards. Following our emergence from bankruptcy, the board of directors determined the size and vesting terms of all awards (other than the Emergence Awards) made under our MIP (and following the formation of the compensation committee in June 2017, based on the recommendation of the compensation committee). The board of directors took a number of factors into account, including, among others, the eligible employee’s expected contribution to the long-term success of the Company, the significant demand in Houston and worldwide for experienced oil and gas executives and information gathered by the board of directors regarding compensation paid to executives at our Predecessor’s master limited partnership peers and at other public oil and gas exploration and production companies. For subsequent years, the compensation committee may take some or all of these factors into account, and may also consider other factors that it deems relevant at the time of determination.

Retention Bonuses and Key Employee Retention Plan. In October 2016, the board of directors of our Predecessor’s general partner approved the adoption of a key employee retention program (“KERP”). The purpose of the KERP was to retain key employees identified by the board of directors of our Predecessor, including the NEOs, whose continued employment and performance is critical to the success of the Company. Under the KERP, during the 2016 fiscal year the Company granted cash retention awards to specified key employees, including the NEOs, which were intended to encourage such employees to continue their employment with us through a specified date in 2017. No additional cash retention awards were granted under the KERP during the 2017 fiscal year, although a portion of the retention bonus awards under the KERP previously granted to Messrs. Smiley and Hoss became vested and were paid at the time of our emergence from bankruptcy.

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On November 27, 2017, we entered into a retention bonus agreement with Mr. Hoss pursuant to which he is eligible to receive an additional cash bonus of $118,000 if he is employed by us on December 31, 2018, or if his employment is terminated by us without “cause” (as defined in the retention bonus agreement).

Change of Control Severance Benefits. On May 4, 2016, the Company entered into change of control agreements with each of Messrs. Scarff, Cooper, Stillwell, Smiley, and Hoss. These change of control agreements require the Company to provide certain compensation and benefits to the executive if the executive’s employment is terminated on account of a qualifying termination (as defined below). The change of control agreements continue in effect until the earlier of (i) a separation from service other than on account of a qualifying termination, (ii) the Company’s satisfaction of all of its obligations under the change of control agreement, or (iii) the execution of a written agreement between the Company and the executive terminating the change of control agreement.

Under the terms of each change of control agreement, if an executive’s employment is terminated on account of a qualifying termination, then subject to such executive’s signing and not revoking a separation agreement and release of claims, then such executive will be entitled to the following payments and benefits:

• A lump sum payment equal to a specified percentage of such executive’s (i) annual base salary and (ii) target bonus, in each case, at the highest rate in effect during the twelve month period prior to the date in which the qualifying termination occurs. For this purpose, the percentage multiplier is 250% for Mr. Scarff, 200% for Messrs. Cooper and Stillwell, and 150% for Messrs. Smiley and Hoss, and the target bonus would be calculated as a percentage of base salary, which was equal to 100% for Mr. Scarff, 90% for Messrs. Cooper and Stillwell, 65% for Mr. Smiley, and 50% for Mr. Hoss for 2017.

• Vesting of all outstanding unvested awards previously granted to such executive under the MIP.

• Reimbursement for the amount of COBRA continuation premiums (less required co-pay) until the earlier of (i) twelve months following the qualifying termination and (ii) such time as such executive is no longer eligible for COBRA continuation coverage.

• Financial counseling services for twelve months following the qualifying termination, subject to a maximum benefit of $30,000.

• Outplacement counseling services for twelve months following the qualifying termination, subject to a maximum value of $30,000.

“Qualifying termination” means, as to any executive, the separation of service on account of (i) an involuntary termination by the Company without “cause” or (ii) such executive’s voluntary resignation for “good reason”, in each case, within six months prior to, or twenty-four months following, a change of control. The term “cause” means (i) such executive’s commission of, conviction for, plea of guilty or nolo contendere to a felony or a crime involving moral turpitude; (ii) engaging in conduct that constitutes fraud, gross negligence or willful misconduct that results or would reasonably be expected to result in material harm to the Company or its affiliates or their respective businesses or reputations; (iii) breach of any material terms of such executive’s employment, including any of the Company’s policies or its code of conduct; or (iv) willful and continued failure to substantially perform such executive’s duties for the Company which such failure is not remedied within ten business days after receipt of written demand of substantial performance by the board of directors. The term “good reason” means the occurrence of one of the following without an executive’s express written consent (i) a material reduction of such executive’s duties, position or responsibilities, or such executive’s removal from such position and responsibilities, unless such executive is offered a comparable position (i.e., a position of equal or greater organizational level, duties, authority, compensation, title and status); (ii) a material reduction by the Company of such executive’s base compensation (base salary and target bonus) as in effect immediately prior to such reduction; (iii) such executive is requested to relocate (except for office relocations that would not increase such executive’s one way commute by more than 50 miles); or (iv) any other action or inaction that constitutes a material breach by the Company of the change of control agreement. The term “change of control” has the meaning ascribed to such term in the MIP as of the Effective Date.

In the event that the board of directors determines that payments to be made to an executive under the change of control agreement would constitute “excess parachute payments” subject to excise tax under Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”), then the amount of such payments shall either (i) be reduced so that such payments will not be subject to such excise tax or (ii) paid in full, whichever results in the better net after tax position for the executive.

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MIP Severance Agreement. In connection with the grant of the Emergence Awards, each executive officer of the Company executed a management incentive plan severance agreement which generally provides that, if the executive is terminated by the Company without “cause” or the executive resigns his employment for “good reason,” in each case, within two years following the Effective Date (the “Severance Agreement Termination”), in lieu of any other severance payments or benefits, such executive will receive a cash amount equal to the greater of (x) such executive’s severance benefits under his change of control agreement (other than the acceleration of equity awards pursuant to the change of control agreement) (the “Change of Control Severance Benefits”) and (y) a cash payment equal to the value of such executive’s unvested Emergence Awards on such termination or resignation date (with the value of any stock options calculated as the spread value of the stock option). However, if the compensation committee determines in its good faith judgment that payment of the Change of Control Severance Benefits is not warranted because the basis of the termination of employment is poor performance which does not otherwise constitute “cause”, the executive officer will only be entitled to a cash payment equal to the value of such executive’s Emergence Awards on such termination or resignation date. Notwithstanding the foregoing, if the Severance Agreement Termination occurs within six months prior to, or twenty-four months following, a change of control of the Company, the executive’s change of control agreement shall control in such event.  

Other Benefits. We do not maintain a defined benefit pension plan for the executive officers. We provide a basic benefits package generally to all employees, which includes a 401(k) plan and eligibility to receive employer matching contributions, and health, disability and life insurance.

Employment Agreements

The Company has not entered into any employment agreements with any of our NEOs, other than change of control agreements and MIP severance agreements.

Compensation Committee Report

Our compensation committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth above. Based on this review and discussion, the compensation committee has recommended to the board of directors of the Company that the Compensation Discussion and Analysis be included in this annual report.

The compensation committee of Amplify Energy Corp.

Christopher Hamm

P. Michael Highum

Evan S. Lederman

David H. Proman

William J. Scarff

Edward A. Scoggins, Jr.

Deductibility of Compensation

In general, Section 162(m) of the Code (“Section 162(m)”), prevents publicly held corporations from deducting, for federal income tax purposes, compensation paid in excess of $1 million to certain executives. Prior to our emergence from bankruptcy, we were a limited partnership that did not meet the definition of a “corporation” subject to deduction limitations under Section 162(m). Accordingly, these limitations did not apply to compensation paid to our NEOs.

Elements of the Company’s executive compensation program, including stock options granted under the MIP, were designed in a manner intended to allow elements thereof to satisfy specific exceptions to the Section 162(m) limit on deductibility related to performance-based compensation. However, pursuant to the 2017 Tax Cuts and Jobs Act signed into law on December 22, 2017 (the “Tax Act”), the exception for performance-based compensation has been repealed, effective for taxable years beginning after December 31, 2017, such that compensation paid to our covered executive officers in excess of $1,000,000 will not be deductible unless it qualifies for transition relief applicable to certain arrangements in place as of November 2, 2017. Because of ambiguities and uncertainties as to the application and interpretation of Section 162(m) and the regulations issued thereunder, including the uncertain scope of the transition relief under the Tax Act, no assurance can be given that compensation intended to satisfy the requirements for exemption from Section 162(m) in fact will satisfy such requirements. Further, the compensation committee reserves the right to modify compensation that was initially intended to be exempt from Section 162(m) if it determines that such modifications are consistent with our business needs.

Pay Ratio Disclosure

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the total annual compensation of our employees and the annual total compensation of our president and chief executive officer:

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For 2017, our last completed fiscal year:

• The median of the total annual compensation of all employees of our Company (excluding our CEO) was $109,698; and

• The total annual compensation of our chief executive officer, as reported in the Summary Compensation Table below, was $3,982,169.

Based on this information, for 2017 the ratio of the annual total compensation of Mr. Scarff, our president and chief executive officer, to the median of the annual total compensation of all employees was 36.30.

To identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our CEO, we took the following steps:

• We determined that, as of December 31, 2017, our employee population consisted of approximately 281 full-time employees, with all of these individuals located in the United States. This population did not include employees who were on leaves of absence as of December 31, 2017, or any part-time or temporary employees.  

• To identify the “median employee” from our employee population, we used cash compensation consisting of base salary and annual bonus, as reflected in our payroll records as reported to the Internal Revenue Service on Form W-2 for 2017. In making this determination, we annualized the base pay or monthly wages and annual bonus amounts paid in respect of 2017 for those full-time employees who did not work for the entire 12-month period.

• Once we identified our median employee, we combined all of the elements of such employee’s compensation for 2017 in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $109,698.

• With respect to the total annual compensation of our CEO, we used the amount reported in the “Total” column of the Summary Compensation Table.

Because the SEC rules for identifying the median compensated employee and calculating the pay ratio based on that employee’s annual total compensation allow companies to adopt a variety of methodologies, to apply certain exclusions, and to make reasonable estimates and assumptions that reflect their compensation practices, the pay ratio reported by other companies may not be comparable to the pay ratio reported above, as other companies may have different employment and compensation practices and may utilize different methodologies, exclusions, estimates and assumptions in calculating their own pay ratios.

Relation of Compensation Policies and Practices to Risk Management

Our compensation policies and practices are designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk-taking. Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessive risks to reach performance thresholds that qualify them for additional compensation.

From a risk management perspective, our policy is to conduct our commercial activities within pre-defined risk parameters that are closely monitored and are structured in a manner intended to control and minimize the potential for unwarranted risk-taking. We also routinely monitor and measure the execution and performance of our projects and acquisitions relative to expectations.

We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking unwarranted risk to achieve short-term, unsustainable results. Those elements include delaying the rewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our Code of Business Conduct and Ethics.

In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

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Summary Compensation Table

The following table includes the compensation earned by our NEOs for the fiscal years ended December 31, 2017, 2016 and 2015 (including amounts paid by our Predecessor prior to our emergence from bankruptcy), and their respective titles as of December 31, 2017.

						Stock		Option		All Other
		Salary		Bonus		Awards		Awards		Compensation		Total
Name and Principal Position	Year	($)		($) (1) (2)		($) (3)		($) (4)		($) (5)		($)
William J. Scarff	2017		600,000		1,000,000		1,733,010		630,529		18,630		3,982,169
President and Chief Executive Officer	2016		327,500		800,000		1,200,000		—		56,234		2,383,734
	2015		175,000		112,000		574,996		—		190,917		1,052,913
Christopher S. Cooper	2017		445,000		638,889		1,211,760		440,880		18,630		2,755,159
Senior Vice President and Chief Operating Officer	2016		322,083		675,000		1,000,000		—		38,081		2,035,165
	2015		175,000		112,000		900,000		—		96,792		1,283,792
Robert L. Stillwell, Jr.	2017		415,000		540,000		908,820		330,660		18,630		2,213,110
Senior Vice President and Chief Financial Officer	2016		298,125		625,000		650,000		—		37,258		1,610,383
	2015		162,500		100,000		750,003		—		82,491		1,094,994
Richard P. Smiley	2017		310,000		481,944		393,822		143,286		18,630		1,347,682
Vice President, Onshore Operations
Matthew J. Hoss	2017		235,000		339,583		240,975		87,675		18,630		921,863
Vice President and Chief Accounting Officer	2016		176,667		100,000		250,000		—		24,301		550,968

(1) The amounts reported for 2017 consist of awards calculated pursuant to the KEIP and in addition, for Mr. Smiley a payment of $162,500 under the KERP, and for Mr. Hoss, a payment of $100,000 under the KERP.

(2) Amounts reported for 2015 and 2016 include payments under the KEIP, and amounts for 2016 also include prior bonus payments made under the KERP. For more information, see "Compensation Discussion and Analysis—Elements of Executive Compensation—Cash Incentive Awards” and “Compensation Discussion and Analysis—Elements of Executive Compensation—Retention Bonuses and Key Employee Retention Plan”.

(3) The amounts reported for 2015 and 2016 represent the aggregate grant date fair value of restricted unit awards and phantom unit awards granted in fiscal 2015 and fiscal 2016 by our Predecessor, calculated in accordance with ASC Topic 718, utilizing the assumptions discussed in Note 13 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.” The amounts reported for 2017 reflect the aggregate grant date fair value of restricted stock units granted in 2017 under our MIP, calculated in accordance with ASC Topic 718, utilizing the assumptions discussed in Note 13 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

(4) The amounts reported reflect the aggregate grant date fair value of the stock option awards granted in fiscal 2017, calculated in accordance with ASC Topic 718 based on an exercise per share of $21.58 and utilizing the assumptions discussed in Note 13 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

(5) All other compensation for the 2017 fiscal year for each of our NEOs includes a matching company contribution under the Company’s defined contribution 401(k) plan equal to $16,200, and the dollar value of life, short- and long-term disability insurance paid on behalf of the officer equal to $2,430.  

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Grants of Plan-Based Awards

The following table sets forth certain information with respect to grants of plan-based awards to our NEOs during the fiscal year ended December 31, 2017.

									All Other		All Other Option
									StockAwards:		Awards: Number		Exercise		Grant Date
			Estimated Possible Payouts						Number of		of Securities		Price of		Fair Value of
			Under Non-Equity Incentive						Shares of Stock		Underlying		Option		Stock and Option
	Award	Grant	Plan Awards (1)						or units (2)		Options (2)		Awards		Awards (3)
Name	Type	Date	Threshold ($)		Target ($)		Maximum ($)		(#)		(#)		($)		($)
William J. Scarff	Cash Incentive Plan			700,000		1,400,000		2,100,000		—				—
	RSU	05/04/17		—		—		—		125,854		—		—		1,733,010
	Stock Options	05/04/17		—		—		—		—		125,854		21.58		630,529
Christopher S. Cooper	Cash Incentive Plan			400,000		800,000		1,200,000		—		—		—		—
	RSU	05/04/17		—		—		—		88,000		—		—		1,211,760
	Stock Options	05/04/17		—		—		—		—		88,000		21.58		440,880
Robert L. Stillwell, Jr.	Cash Incentive Plan			400,000		800,000		1,200,000		—		—		—		—
	RSU	05/04/17		—		—		—		66,000		—		—		908,820
	Stock Options	05/04/17		—		—		—		—		66,000		21.58		330,660
Richard P. Smiley	Cash Incentive Plan			200,000		400,000		600,000		—		—		—		—
	RSU	05/04/17		—		—		—		28,600		—		—		393,822
	Stock Options	05/04/17		—		—		—		—		28,600		21.58		143,286
Matthew J. Hoss	Cash Incentive Plan			150,000		300,000		450,000		—		—		—		—
	RSU	05/04/17		—		—		—		17,500		—		—		240,975
	Stock Options	05/04/17		—		—		—		—		17,500		21.58		87,675

(1) Reflects the possible payouts under the KEIP described under "Compensation Discussion and Analysis—Elements of Executive Compensation—Cash Incentive Awards." The actual amounts paid are described in the “Bonus” column of the Summary Compensation Table.  

(2) As described in further detail under “Compensation Discussion and Analysis—Elements of Executive Compensation—Long Term Incentive Compensation,” the RSUs and stock options granted as part of the Emergence Awards generally vest in three equal annual installments, beginning on the first anniversary of the date of grant.  

(3) Reflects the aggregate grant date fair value of RSUs and stock options granted under the MIP calculated in accordance with the ASC Topic 718, without taking into account estimated forfeitures, based on the fair market value of a share of our common stock on the date of grant. For information about assumptions made in the valuation of these awards, see Note 13 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

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Outstanding Equity Awards

The following table sets forth certain information with respect to outstanding equity awards at December 31, 2017.

		Option Awards									Stock Awards
Name	Grant Date	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards:  Number of Securities Underlying Unexercised Unearned Options (#)		Option Exercise Price ($)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)		Equity Incentive Plan Awards:  Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value Of Unearned Shares, Units or Other Rights That Have Not Vested ($) (1)
William J. Scarff	5/4/2017 (2)		—		125,854		—		21.58	5/4/2023		—		—		—		—
	5/4/2017 (3)		—		—		—		—			125,854		1,277,418		—		—
Christopher S. Cooper	5/4/2017 (2)		—		88,000		—		21.58	5/4/2023		—		—		—		—
	5/4/2017 (3)		—		—		—		—			88,000		893,200		—
Robert L. Stillwell, Jr.	5/4/2017 (2)		—		66,000		—		21.58	5/4/2023		—		—		—		—
	5/4/2017 (3)		—		—		—		—			66,000		669,900		—		—
Richard Smiley	5/4/2017 (2)		—		28,600		—		21.58	5/4/2023		—		—		—		—
	5/4/2017 (3)		—		—		—		—			28,600		290,290		—		—
Matthew J. Hoss	5/4/2017 (2)		—		17,500		—		21.58	5/4/2023		—		—		—		—
	5/4/2017 (3)		—		—		—		—			17,500		177,625		—		—

(1) Amounts reported are based on the fair market value of our common stock on the last day of the fiscal year ended December 31, 2017 ($10.15).

(2) Reflects stock options which vest over three years in equal annual installments on the anniversary of the grant date.

(3) Reflects RSUs which vest over three years in equal annual installments on the anniversary of the grant date.

Option Exercises and Stock Vested

The following table sets forth certain information with respect to equity-based awards held by our NEOs that vested during the fiscal year ended December 31, 2017.  

	Option Awards				Stock Awards
	Number of  Shares		Value		Number of  Shares		Value
	Acquired on		Realized on		Acquired on		Realized on
Name	Exercise (#)		Exercise ($)		Vesting (#) (1)		Vesting ($) (2)
William J. Scarff (3)		—		—		55,429		6,651
Christopher S. Cooper		—		—		598,046		18,361
Robert L. Stillwell, Jr.		—		—		405,984		13,858
Richard P.  Smiley		—		—		232,000		6,419
Matthew J. Hoss		—		—		144,515		3,934

(1) Amounts reported consist of restricted units and phantom units granted by our Predecessor under the LTIP. Restricted units became vested in accordance with their terms, and phantom units were cancelled in connection with our emergence from bankruptcy in exchange for a one-time payment, including 558,659  phantom units held by Mr. Cooper, 363,128 phantom units held by Mr. Stillwell, 223,464 phantom units held by Mr. Smiley, and 139,665 phantom units held by Mr. Hoss.

(2) Amounts reported include one-time payments received in respect of phantom units, which were cancelled in connection with our emergence from bankruptcy, including $13,408 paid to Mr. Cooper in respect of cancelled phantom units, $8,715 paid to Mr. Stillwell in respect of cancelled phantom units, $5,363 paid to Mr. Smiley in respect of cancelled phantom units, and $3,352 paid to Mr. Hoss in respect of cancelled phantom units.

(3) Amount reported in the column “Number of Shares Acquired on Vesting” does not include 670,391 phantom units held by Mr. Scarff which were cancelled without consideration in connection with our emergence from bankruptcy.

Pension Benefits

Currently, the Company does not, and does not intend to, provide pension benefits to NEOs.

Nonqualified Deferred Compensation

Currently, the Company does not, and does not intend to, sponsor or adopt a nonqualified deferred compensation plan.

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Potential Payments Upon Termination or Change of Control

The following table sets forth information concerning the change of control and severance payments to be made to each of our NEOs in connection with a change of control or termination of employment, presuming a termination or change of control date of December 31, 2017 and the fair market value of a share of common stock on December 31, 2017 ($10.15 per share). The below table only includes information for employment termination or change of control events that trigger vesting or severance-related payments, and assumes that each executive will take all action necessary or appropriate for such person to receive the maximum available benefit, such as execution of a release of claims. Additional descriptions of the terms of our agreements, plans, and arrangements with our NEOs are set forth in “Item 11. Executive Compensation — Compensation Discussion and Analysis — Elements of Executive Compensation.”

The precise amount that each of our NEOs would receive cannot be determined with any certainty until a change of control has occurred.  

Name	Involuntary Termination during Change of Control Protection Period ($) (1)		Involuntary Termination (No Change of Control) ($) (2)		Other Involuntary Termination ($) (3)		Termination for Cause or Voluntary Resignation without Good Reason ($)		Termination upon Death or Disability ($) (4)
William J. Scarff
Cash Severance	$	3,000,000	$	3,000,000	$	1,277,418	$	—	$	—
Accelerated Equity Compensation (5)		1,277,418		—		—		—		1,277,418
Health and Welfare Benefits		15,983		15,983		—		—		—
Financial Counseling		30,000		30,000		—		—		—
Outplacement Assistance		30,000		30,000		—		—		—
Total	$	4,353,401	$	3,075,983	$	1,277,418	$	—	$	1,277,418
Christopher S. Cooper
Cash Severance	$	1,691,000	$	1,691,000	$	893,200	$	—	$	—
Accelerated Equity Compensation (5)		893,200		—		—		—		893,200
Health and Welfare Benefits		19,588		19,588		—		—		—
Financial Counseling		30,000		30,000		—		—		—
Outplacement Assistance		30,000		30,000		—		—		—
Total	$	2,663,788	$	1,770,588	$	893,200	$	—	$	893,200
Robert L. Stillwell, Jr.
Cash Severance	$	1,577,000	$	1,577,000	$	669,900	$	—	$	—
Accelerated Equity Compensation (5)		669,900		—		—		—		669,900
Health and Welfare Benefits		24,488		24,488		—		—		—
Financial Counseling		30,000		30,000		—		—		—
Outplacement Assistance		30,000		30,000		—		—		—
Total	$	2,331,388	$	1,661,488	$	669,900	$	—	$	669,900
Richard Smiley
Cash Severance	$	767,250	$	767,250	$	290,290	$	—	$	—
Accelerated Equity Compensation (5)		290,290		—		—		—		290,290
Health and Welfare Benefits		15,983		15,983		—		—		—
Financial Counseling		30,000		30,000		—		—		—
Outplacement Assistance		30,000		30,000		—		—		—
Total	$	1,133,523	$	843,233	$	290,290	$	—	$	290,290
Matthew J. Hoss
Cash Severance	$	528,750	$	528,750	$	166,625	$	—	$	—
Accelerated Equity Compensation (5)		166,625		—		—		—		166,625
Health and Welfare Benefits		15,983		15,983		—		—		—
Financial Counseling		30,000		30,000		—		—		—
Outplacement Assistance		30,000		30,000		—		—		—
Retention Bonus (6)		118,000		118,000		118,000		—		—
Total	$	889,358	$	722,733	$	284,625	$	—	$	166,625

(1) If an NEO’s employment is terminated by us without cause or due to the NEO’s resignation with good reason (a “Qualifying Termination”) during the period beginning six months prior to, and ending 24 months after, a change of control (a “Change of Control Protection Period”), the NEO will be entitled to the severance benefits set forth in the applicable Change of Control Agreement described above under “Compensation Discussion and Analysis — Elements of Executive Compensation — Change of Control Severance Benefits.”

(2) If a NEO experiences a Qualifying Termination other than during the Change of Control Protection Period, the NEO is entitled to a cash severance payment calculated as the greater of (i) the cash severance payment, COBRA premium reimbursement, financial counseling, and outplacement assistance described above under “Compensation Discussion and Analysis — Elements of Executive Compensation — Change of Control Severance Benefits” (collectively, the “Change of Control Severance Benefits”), or (ii) the value of unvested portion of the Emergence Awards granted to the NEO on May 4, 2017. As of December 31, 2017, for each NEO, the value of the Change of Control Severance Benefits exceeded the aggregate value of the Emergence Awards, and as a result the NEO would have been entitled to the Change of Control Severance Benefits.

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(3) If an NEO’s employment is terminated by us without cause, other than during the Change of Control Protection Period, and the compensation committee determines the grounds for termination of employment is due to poor performance which does not constitute cause under the terms of the MIP Severance Agreement, the NEO will only be entitled to a cash severance payment equal to the aggregate value of such NEO’s unvested Emergence Award, calculated as of the date of termination of employment. Accordingly, amounts shown reflect the market value of the Emergence Awards as of December 31, 2017.

(4) If an NEO’s employment is terminated by us while the NEO is disabled, or if the NEO’s employment terminates as a result of the NEO’s death, all unvested RSUs will become vested, and the portion of the stock options granted as Emergence Awards which would become vested on the next annual vesting date will vest on the date of termination. As of December 31, 2017, the exercise price applicable to all stock options granted as Emergence Awards was greater than the fair market value of the underlying common share. Accordingly, the amounts shown do not include any value attributable to any stock options which would become vested as a result of the specified termination.

(5) Amount reflects market value of outstanding RSUs which would become vested in connection with the specified termination. As of December 31, 2017, the exercise price applicable to all stock options granted as Emergence Awards was greater than the fair market value of the underlying common share. Accordingly, the amounts shown do not include any value attributable to any stock options which would become vested as a result of the specified termination.  

(6) In addition to the payments under his Change of Control Agreement and MIP Severance Agreement, as applicable, if Mr. Hoss’s employment is terminated by us without Cause, he is entitled to payment of the Retention Bonus. He is not entitled to payment of the Retention Bonus upon any resignation from his employment, including a resignation with Good Reason for purposes of the MIP.

Director Compensation

Each director who was not an officer or employee of the Company or our Predecessor’s general partner or its affiliates, other than Messrs. Proman, Lederman, and Shayevsky, received compensation as a “non-employee director” for attending meetings of the board of directors and committee meetings. The following table presents information regarding compensation paid to the independent directors of the Company and our Predecessor’s general partner during the fiscal year ended December 31, 2017.

	Fees Earned		Stock
	or Paid in Cash		Awards		Total
Name	($)		($)(5)		($)
Jonathan M. Clarkson (1)		170,500		—		170,500
P. Michael Highum (2)		169,800		66,726		236,526
W. Donald Brunson (1)		120,556		—		120,556
John A. Weinzierl (1)		120,556		—		120,556
David H. Proman (3)		—		—		—
Christopher W. Hamm		49,245		66,726		115,971
Evan S. Lederman (3)		—		—		—
Edward A. Scoggins, Jr.		49,245		66,726		115,971
Alex Shayevsky (4)		—		—		—

(1) Messrs. Clarkson, Brunson, and Weinzierl served on the board of directors of our Predecessor until our emergence from bankruptcy. Amounts shown for these individuals in the column “Fees Earned or Paid in Cash” consists of compensation and fees paid in respect of service prior to our emergence from bankruptcy.

(2) Mr. Highum served on the board of directors of our Predecessor prior to our emergence from bankruptcy, and on our board of directors following our emergence from bankruptcy. Amounts shown in the column “Fees Earned or Paid in Cash” consists of compensation paid on the same terms as our other non-employee directors before and after our emergence from bankruptcy.

(3) Messrs. Proman, Lederman, and Shayevsky did not receive any compensation for their service on the board of directors in 2017.

(4) Mr. Shayevsky resigned from our board of directors on January 9. 2018.

(5) Reflects the aggregate grant date fair value of RSUs granted under our Non-Employee Directors Compensation Plan, calculated in accordance with ASC Topic 718. For information about assumptions made in the valuation of these awards, see Note 13 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.” RSUs generally vest in equal, annual installments over the three-year period following the date of grant.

Prior to our emergence from bankruptcy, the non-employee directors of our Predecessor received the following compensation, payable quarterly in advance: (i) an annual retainer of $250,000 for each director; (ii) a supplemental quarterly retainer of $25,000; (iii) an annual retainer of $125,000 for the non-executive chairman of the board of directors; and (iv) an annual retainer of $20,000 for the chairman of the audit committee.

Following our emergence from bankruptcy, our non-employee directors receive an annual retainer of $75,000 for each director, paid quarterly in advance, and (ii) an annual equity award of RSUs granted on or about May 1 of each year, with the number of RSUs calculated as $75,000 divided by the fair market value of a share of our common stock on the date of grant.

Non-employee directors are reimbursed for all out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

Compensation Committee Interlocks and Insider Participation

Prior to our emergence from bankruptcy, the Predecessor was a limited partnership, and was not required by applicable NASDAQ listing standards to establish a compensation committee. Following our emergence from bankruptcy, we established a compensation committee consisting of Christopher Hamm, P. Michael Highum, Evan S. Lederman, David H. Proman, William J. Scarff, Edward A. Scoggins, Jr. and Alex Shayevksy (who resigned effective January 9, 2018).

Mr. Scarff served as our President and Chief Executive Officer during fiscal 2017. No member of the compensation committee had any relationships with the Company requiring disclosure under any paragraph of Item 404 of Regulation S-K.

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During 2017, none of our executive officers served on the board of directors or compensation committee of a company that had an executive officer that served on our board of directors. During 2017, no member of our board of directors was an executive officer of a company in which one of our executive officers served as a member of the board of directors or compensation committee of that company.  

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

As of February 23, 2018, the following table sets forth the beneficial ownership of our common stock that are owned by:

• each person known by us to be a beneficial owner of more than 5% of our outstanding common shares;

• each director;

• each executive officer; and

• all executive officers and directors as a group.

Name of Beneficial Owner (1)	Shares of CommonStock Beneficially Owned (2)		Percentage of Common Stock BeneficiallyOwned (3)
Fir Tree Capital Management LO (4)		7,693,278		30.8	%
Brigade Capital Management, LP (5)		4,226,644		16.9	%
Axys Capital Income Fund, LLC (6)		1,875,307		7.5	%
York Capital Management Global Advisors, LLC (7)		1,797,279		7.2	%
Citadel Equity Fund Ltd. (8)		1,771,585		7.1	%
William J. Scarff (9)		84,224	*
Christopher S. Cooper (10)		58,916	*
Robert L. Stillwell, Jr. (11)		44,269	*
Eric M. Willis		—		—
Richard P. Smiley (12)		19,067	*
Matthew J. Hoss (13)		11,679	*
David H. Proman (4)		—		—
Christopher W. Hamm (14)		1,816	*
P. Michael Highum (15)		1,816	*
Evan S. Lederman (4)		—		—
Edward A. Scoggins, Jr. (16)		1,816	*
All executive officers and directors as a group (11 persons)		223,603	*
*   Less than 1.0%

(1) Unless otherwise noted, the address for all beneficial owners in this table is 500 Dallas Street, Suite 1600, Houston, Texas 77002.

(2) The amounts and percentages of common stock beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest.

(3) Based on 25,000,000 shares of common stock outstanding at February 23, 2018. Shares of common stock (i) issuable upon the vesting of RSUs within 60 days of the filing date of this annual report, and (ii) subject to stock options that are currently exercisable or exercisable within 60 days of the filing date of this annual report, are deemed to be outstanding for the purpose of computing the percentage ownership of the person holding those RSUs or stock options, but are not treated as outstanding for the purpose of computing the percentage ownership (x) of any other person or (y) of the aggregate held by all executive officers and directors as a group.

(4) The address of this beneficial owner is 55 West 46th Street, New York, NY 10036. Consists of (i) 295,979 shares owned by Fir Tree Capital Opportunity Master Fund III, LP, (ii) 177,227 shares owned by FT SOF IV Holdings, LLC, (iii) 3,936,185 shares owned by Fir Tree E&P Holdings VII, LLC and (iv) 3,283,887 shares owned by Fir Tree E&P Holdings VIII, LLC (collectively, the “Fir Tree funds”). Fir Tree Capital Management LP (“FTCM”) (f/k/a Fir Tree Inc.) is the investment manager for the Fir Tree funds. Jeffrey Tannenbaum, David Sultan and Clinton Biondo control FTCM. Each of FTCM, Messrs. Tannenbaum, Sultan and Biondo has voting and investment power with respect to the shares of common stock owned by the Fir Tree funds and may be deemed to be the beneficial owner of such shares.  Evan S. Lederman and David H. Proman are directors of the Company and managing directors of FTCM. Messrs. Lederman and Proman do not have voting and investment power with respect to the shares of common stock owned by the Fir Tree funds in their capacities as managing directors of FTCM.

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(5) The address of this beneficial owner is 399 Park Ave. Suite 1600, New York, NY 10022. Consists of (i) 16,163 shares owned by Future Directions Credit Opportunities Fund, (ii) 478,746 shares owned by Brigade Credit Fund II Ltd., (iii) 16,101 shares owned by Big River Group Fund SPC LLC, (iv) 44,760 shares owned by Blue Pearl B 2015 Limited, (v) 142,249 shares owned by Blue Falcon Limited, (vi) 50,005 shares owned by Delta Master Trust, (vii) 217,826 shares owned by Brigade Distressed Value Master Fund Ltd., (viii) 410,000 shares owned by Brigade Energy Opportunities Fund II LP, (ix) 900,000 shares owned by Brigade Energy Opportunities Fund LP, (x) 52,910 shares owned by FedEx Corporation Employees’ Pension Trust, (xi) 20,733 shares owned by Brigade Opportunistic Credit Fund - ICIP, Ltd., (xii) 24,971 shares owned by Illinois State Board of Investment, (xiii) 18,133 shares owned by FCA Canada Inc. Elected Master Trust, (xiv) 19,581 shares owned by FCA US LLC Master Retirement Trust, (xv) 40,608 shares owned by JPMorgan Chase Retirement Plan Brigade Bank Loan, (xvi) 28,321 shares owned by JPMorgan Chase Retirement Plan Brigade, (xvii) 187,760 shares owned by Brigade Opportunistic Credit LBG Fund Ltd., (xviii) 115,162 shares owned by Los Angeles County Employees Retirement Association, (xix) 855,295 shares owned by Brigade Leveraged Capital Structures Fund Ltd., (xx) 39,859 shares owned by Goldman Sachs Trust II - Goldman Sachs Multi Manager Alternatives Fund, (xxi) 13,797 shares owned by Goldman Sachs Funds II SICAV - Goldman Sachs Global Multi-Manager Alternatives Portfolio, (xxii) 31,751 shares owned by SC Credit Opportunities Mandate LLC, (xxiii) 26,552 shares owned by U.S. High Yield Bond Fund, (xxiv) 53,321 shares owned by SEI Global Master Fund Plc the SEI High Yield Fixed Income Fund, (xxv) 147,449 shares owned by SEI Institutional Investments Trust-High Yield Bond Fund, (xxvi) 100,766 shares owned by SEI Institutional Managed Trust-High Yield Bond Fund, (xxvii) 22,852 shares owned by GIC Private Limited, (xxviii) 61,213 shares owned by The Coca-Cola Company Master Retirement Trust, (xxix) 51,458 shares owned by St. James’s Place Diversified Bond Unit Trust, and (xxx) 38,302 shares owned by Brigade Opportunistic Credit Fund 16 LLC (collectively, the “Brigade funds”). Brigade Capital Management, LP has voting and investment power with respect to the shares of common stock owned by the foregoing entities and may be deemed to be the beneficial owner of the shares of common stock owned by the Brigade funds.

(6) The address of this beneficial owner is 1613 South Capital of Texas Hwy, Suite 201, Austin, TX 78746. Trust Asset Management LLC has voting and investment power with respect to the common stock owned by Axys Capital Income Fund, LLC and may be deemed to be the beneficial owner of the shares of common stock owned by Axys Capital Income Fund, LLC. Additionally, Christopher W. Hamm is a director of the Company and chief executive officer of Axys Capital Management, an affiliate of Axys Capital Income Fund, LLC, and therefore may be deemed to be the beneficial owner of, and to have voting and investment control over, the shares of common stock owned by Axys Capital Income Fund, LLC. Mr. Hamm disclaims beneficial ownership of the shares of common stock owned by the Axys fund.

(7) The address of this beneficial owner is 767 Fifth Avenue, New York, NY 10153. Consists of (i) 953,641 shares owned by York Credit Opportunities Investments Master Fund L.P., (ii) 800,635 shares owned by York Credit Opportunities Fund, L.P., (iii) 43,003 shares owned by Exuma Capital, L.P. (collectively, the “York funds”). York Capital Management Global Advisors, LLC has voting and investment power with respect to the common stock owned by the foregoing entities and may be deemed to be the beneficial owner of the shares of common stock owned by the York funds.

(8) The address of this beneficial owner is 131 South Dearborn St., Chicago, IL 60603. Citadel Advisors LLC has voting and investment power with respect to the common stock owned by Citadel Equity Fund Ltd. and may be deemed to be the beneficial owner of the shares of common stock owned by the Citadel Equity Fund Ltd.

(9) Includes 41,951 RSUs that vest, and 41,951 stock options that became exercisable, on May 4, 2018.

(10) Includes 29,333 RSUs that vest and 29,333 stock options that became exercisable, on May 4, 2018.

(11) Includes 22,000 RSUs that vest and 22,000 stock options that became exercisable, on May 4, 2018.

(12) Includes 9,533 RSUs that vest and 9,533 stock options that became exercisable, on May 4, 2018.

(13) Includes 5,833 RSUs that vest and 5,833 stock options that became exercisable, on May 4, 2018.

(14) Reflects RSUs that vest on May 4, 2018, which are held in a margin account by Mr. Hamm.

(15) Reflects RSUs that vest on May 4, 2018.

(16) Reflects RSUs that vest on May 4, 2018.

Our named executive officers also beneficially own derivative securities. See “Item 11. Executive Compensation” for additional information.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of December 31, 2017:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans not approved by security holders:
Management Incentive Plan (1)	—	—		1,122,214
2017 Non-Employee Directors Compensation Plan (2)	—	—		183,659

(1) The Company adopted the Management Incentive Plan in May 2017 in connection with the emergence from Chapter 11. See “Item 11. Executive Compensation—Compensation Discussion and Analysis—Elements of Executive Compensation—Long Term Incentive Compensation” for additional information.

(2) The Company adopted the Non-Employee Directors Compensation Plan in June 2017 following our emergence from Chapter 11. See “Item 11. Executive Compensation — Director Compensation” for additional information.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

In the ordinary course of the Company’s business, the Company purchases products or services from, or engages in other transactions with, various third parties. Occasionally, these transactions may involve entities that are affiliated with one or more members of the Company’s board of directors.

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Related Party Agreements

Since January 1, 2017, no transactions have occurred, and no transactions are currently proposed, in which the Company was or is to be a participant, involving an amount exceeding $120,000 and in which any related person had or will have a direct or indirect material interest.

Review, Approval or Ratification of Transactions with Related Persons

We maintain a policy for approval of related party transactions. A “related party transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “related person” means:

• any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

• any person who is known by us to be the beneficial owner of more than 5% of our common stock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and

• any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

The policy and procedures for reviewing related party transactions are derived from our Code of Business Conduct and Ethics and the charter of the audit committee. Under its charter, the audit committee is responsible for reviewing all material facts of all related party transactions, including transactions for which disclosure would be required under Item 404(a) of Regulation S-K.

Director Independence

Our common stock is quoted for trading on OTCQX. Pursuant to OTCQX rules, we are required to have at least two independent members of our board of directors. The board of directors has determined that, under OTCQX rules, Messrs. Hamm, Highum, Lederman, Proman and Scoggins are independent directors, based on information provided by the directors.

Indemnification of Officers and Directors

Section 145 of the DGCL authorizes a court to award, or a corporation’s board of directors to grant, indemnity to directors and officers in terms sufficiently broad to permit such indemnification under certain circumstances for liabilities, including reimbursements for expenses incurred arising under the Securities Act.

Our amended and restated certificate of incorporation provides that a director will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except:

• for any breach of the duty of loyalty;

• for acts or omissions not in good faith or which involve intentional misconduct or knowing violations of law;

• for liability under Section 174 of the Delaware General Corporation Law (the “DGCL”) (relating to unlawful dividends, stock repurchases or stock redemptions); or

• for any transaction from which the director derived any improper personal benefit.

The effect of this provision is to eliminate our rights, and our stockholders’ rights, to recover monetary damages against a director for breach of a fiduciary duty of care as a director. This provision does not limit or eliminate our rights or those of any stockholder to seek non-monetary relief such as an injunction or rescission in the event of a breach of a director’s duty of care. The provisions will not alter the liability of directors under federal securities laws. In addition, our amended and restated certificate of incorporation provides that we indemnify each director and the officers, employees and agents determined by our board of directors to the fullest extent provided by the laws of the State of Delaware. Our amended and restated certificate of incorporation also requires us to advance expenses, including attorneys’ fees, to our directors and officers in connection with legal proceedings, subject to very limited exceptions.

Any amendment to or repeal of these provisions will not adversely affect any right or protection of our directors in respect of any act or failure to act that occurred prior to any amendment to or repeal of such provisions or the adoption of an inconsistent provision. If the DGCL is amended to provide further limitation on the personal liability of directors of corporations, then the personal liability of our directors will be further limited to the greatest extent permitted by the DGCL. In addition, we have entered into separate indemnification agreements with each of our directors and executive officers. We also maintain director and officer liability insurance.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The audit committee of the board of directors selected KPMG LLP (“KPMG”), an independent registered public accounting firm, to audit our consolidated and combined financial statements for the period from May 5, 2017 through December 31, 2017 and the period from January 1, 2017 through May 4, 2017. The audit committee’s charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to this annual report for the period from May 5, 2017 through December 31, 2017 and January 1, 2017 through May 4, 2017 were approved by the audit committee.

The following table summarizes the aggregate KPMG fees for independent auditing, tax and related services for each of the last two fiscal years (dollars in thousands):

	2017		2016
Audit fees (1)	$	1,245	$	1,185
Audit-related fees (2)		—		25
Tax fees (3)		—		—
All other fees (4)		—		—
Total	$	1,245	$	1,210

(1) Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. For 2017 and 2016, those fees primarily related to the (i) audit of our annual financial statements and internal controls over financial reporting included in our annual reports, (ii) the review of our quarterly financial statements filed on Form 10-Q, (iii) services in connection with the Company’s emergence from bankruptcy, and (iv) services in connection with the at-the-market program.

(2) Audit-related fees represent amounts billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews. For 2016, these fees primarily related to an agreed-upon procedures report in connection with the Predecessor’s royalty relief program. No such services were rendered by KPMG during the years ended December 31, 2017.

(3) Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning. No such services were rendered by KPMG during the year ended December 31, 2017 and 2016.

(4) No such services were rendered by KPMG during the years ended December 31, 2017 and 2016.

Audit Committee Approval of Audit and Non-Audit Services

The audit committee of the board of directors has adopted a pre-approval policy with respect to services which may be performed by KPMG. This policy lists specific audit-related services as well as any other services that KPMG is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee prior to engagement.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

Our Consolidated and Combined Financial Statements are included under Part II, “Item 8. Financial Statements and Supplementary Data” of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” Page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated and combined financial statements or notes thereto.

(a)(3) Exhibits

The exhibits listed on the Exhibit Index below are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

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Exhibit Index

Exhibit Number		Description
2.1	—		Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2017).
2.2##	—		Purchase and Sale Agreement, dated as of November 3, 2015, by and between SP Beta Holdings, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on November 5, 2015).
2.3##	—	Purchase and Sale Agreement, dated as of April 27, 2016, among Memorial Production Partners LP, Memorial Resources Development Corp., Memorial Production Partners GP LLC, Memorial Production Operating LLC, Beta Operating Company, LLC and MEMP Services LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 2, 2016).
2.4##	—	Joint Plan of Reorganization of Memorial Production Partners LP, et al. under Chapter 11 of the Bankruptcy Code, dated as of January 16, 2017 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on January 17, 2017).
3.1	—	Amended and Restated Certificate of Incorporation of Amplify Energy Corp. (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-8 (File No. 333-217674) filed on May 4, 2017).
3.2	—	Amended and Restated Bylaws of Amplify Energy Corp. (incorporated by reference to Exhibit 4.2 of the Company’s Registration Statement on Form S-8 (File No. 333-217674) filed on May 4, 2017).
4.1#	—	Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011).
4.2#	—	Form of Phantom Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.2 to Annual Report on Form 10-K (File No. 001-35364) filed on February 24, 2016).
4.3	—	Indenture, dated April 17, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2013).
4.4	—	First Supplemental Indenture, dated as of October 7, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on November 7, 2013).
4.5	—	Second Supplemental Indenture, dated as of December 30, 2015, by and among San Pedro Bay Pipeline Company, Memorial Production Partners LP, Memorial Production Finance Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.5 to Annual Report on Form 10-K (File No. 001-35364) filed on February 24, 2016).
4.6	—	Indenture, dated July 17, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2014).
4.7	—	First Supplemental Indenture, dated as of December 30, 2015, by and among San Pedro Bay Pipeline Company, Memorial Production Partners LP, Memorial Production Finance Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.7 to Annual Report on Form 10-K (File No. 001-35364) filed on February 24, 2016).
4.8	—	Instrument of Resignation, Appointment and Acceptance, dated as of June 24, 2016, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, Wilmington Trust, National Association, as successor trustee, and U.S. Bank National Association, as resigning trustee (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 3, 2016).

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Exhibit Number		Description
4.9	—	Instrument of Resignation, Appointment and Acceptance, dated as of June 24, 2016, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, Wilmington Trust, National Association, as successor trustee, and U.S. Bank National Association, as resigning trustee (incorporated by reference to Exhibit 4.4 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 3, 2016).
4.10	—	Second Supplemental Indenture, dated as of July 20, 2016, by and among Memorial Production Partners GP LLC, MEMP Services LLC, Beta Operating Company, LLC, Memorial Production Partners LP, Memorial Production Finance Corporation, the other subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 3, 2016).
4.11	—	Third Supplemental Indenture, dated as of July 20, 2016, by and among Memorial Production Partners GP LLC, MEMP Services LLC, Beta Operating Company, LLC, Memorial Production Partners LP, Memorial Production Finance Corporation, the other subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.6 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 3, 2016).
10.1#	—	Form of Change of Control Agreement (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 4, 2016).
10.2#	—	Form of Key Employee Retention Bonus Agreement for Senior Management (incorporated by reference to Exhibit 10.5 to Annual Report on Form 10-K (File No. 001-35364) filed on March 10, 2017).
10.3#	—	Form of Key Employee Retention Bonus Agreement (incorporated by reference to Exhibit 10.6 to Annual Report on Form 10-K (File No. 001-35364) filed on March 10, 2017).
10.4#	—	Memorial Production Partners LP Key Employee Incentive Plan (incorporated by reference to Exhibit 10.7 to Annual Report on Form 10-K (File No. 001-35364) filed on March 10, 2017).
10.5		Plan Support Agreement, dated as of December 22, 2016, among Memorial Production Partners LP (the “Partnership”) and its subsidiaries party thereto and certain holders of the Partnership’s 7.625% Senior Notes due 2021 and the Partnership’s 6.875% Senior Notes due 2022 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 23, 2016).
10.6		Plan Support Agreement, dated as of January 13, 2017, among Memorial Production Partners LP and its subsidiaries party thereto and the banks party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on January 17, 2017).
10.7		Amendment to Plan Support Agreement, dated as of January 12, 2017, among Memorial Production Partners LP (the “Partnership”) and its subsidiaries party thereto and certain holders of the Partnership’s 7.625% Senior Notes due 2021 and the Partnership’s 6.875% Senior Notes due 2022 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-35364) filed on January 17, 2017).
10.8#		Amplify Energy Corp. Management Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (File No. 333-217674) filed on May 4, 2017).
10.9#		Form of Stock Option Award Agreement (incorporated by reference to Exhibit 99.2 of the Company’s Registration Statement on Form S-8 (File No. 333-217674) filed on May 4, 2017).
10.10#	—	Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 99.3 of the Company’s Registration Statement on Form S-8 (File No. 333-217674) filed on May 4, 2017).
10.11	—	Amended and Restated Credit Agreement, dated as of May 4, 207, among Amplify Energy Operating LLC, Amplify Acquisitionco Inc., as a parent guarantor, the lenders from time to time party thereto and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2017).
10.12#	—	Stockholders Agreement, dated as of May 4, 2017, between the Company and certain Stockholders (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2017).

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Exhibit Number				Description
10.13	—			Registration Rights Agreement, dated as of May 4, 2017, between the Company and certain Stockholders (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2017).
10.14	—			Warrant Agreement between Amplify Energy Corp., as Issuer, and American Stock Transfer & Trust Company, LLC, as Warrant Agent, dated as of May 4, 2017 (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2017).
10.15#	—			Form of Amendment to the Change of Control Agreement (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2017).
10.16#	—			Form of Amendment to the Management Incentive Plan Severance Agreement (incorporated by reference to Exhibit 10.6 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2017).
10.17#	—			Amplify Energy Corp. Amended and Restated Key Employee Incentive Plan (incorporated by reference to Exhibit 10.7 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2017).
10.18#	—			Amplify Energy Corp. 2017 Non-Employee Directors Compensation Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (File No. 333-218745) filed on June 14, 2017).
10.19#	—			Form of Restricted Stock Unit Award Agreement under the Amplify Energy Corp. 2017 Non-Employee Directors Compensation Plan (incorporated by reference to Exhibit 99.2 of the Company’s Registration Statement on Form S-8 (File No. 333-218745) filed on June 14, 2017).
10.20	—			First Amendment to Amended and Restated Credit Agreement, dated as of November 30, 2017, among Amplify Energy Operating LLC, the guarantors party thereto, lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-35364) filed on December 6, 2017).
21.1*	—			List of Subsidiaries of Amplify Energy Corp.
23.1*	—			Consent of Ryder Scott Company, L.P.
23.2*		—	Consent of KPMG LLP
31.1*	—			Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
31.2*	—			Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
32.1*	—			Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	—			Report of Ryder Scott Company, L.P.
101.CAL*	—			XBRL Calculation Linkbase Document
101.DEF*	—			XBRL Definition Linkbase Document
101.INS*	—			XBRL Instance Document
101.LAB*	—			XBRL Labels Linkbase Document
101.PRE*	—			XBRL Presentation Linkbase Document
101.SCH*	—			XBRL Schema Document

* Filed or furnished as an exhibit to this Annual Report on Form 10-K.

# Management contract or compensatory plan or arrangement.

## Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

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ITEM 16. Form 10-K Summary

None.

96

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Amplify Energy Corp.
	(Registrant)
Date: March 12, 2018	By:	/s/ Robert L. Stillwell, Jr.
	Name:	Robert L. Stillwell, Jr.
	Title:	Senior Vice President and Chief Financial Officer

97

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated.

Name	Title (Position with Amplify Energy Corp.)	Date
/s/ William J. Scarff	President, Chief Executive Officer and Director	March 12, 2018
William J. Scarff	(Principal Executive Officer)
/s/ Robert L. Stillwell, Jr.	Senior Vice President and Chief Financial Officer	March 12, 2018
Robert L. Stillwell, Jr.	(Principal Financial Officer)
/s/ Matthew J. Hoss	Vice President and Chief Accounting Officer	March 12, 2018
Matthew J. Hoss	(Principal Accounting Officer)
/s/ David H. Proman	Director and Chairman	March 12, 2018
David H. Proman
/s/ Christopher W. Hamm	Director	March 12, 2018
Christopher W.  Hamm
/s/ P. Michael Highum	Director	March 12, 2018
P. Michael Highum
/s/ Evan S. Lederman	Director	March 12, 2018
Evan S. Lederman
/s/ Edward A. Scoggins, Jr.	Director	March 12, 2018
Edward A. Scoggins, Jr.

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

No annual report, proxy statement, form of proxy, or other proxy soliciting material has been sent to the registrant's security holders. The registrant undertakes to furnish to the Commission any annual report or proxy material which it delivers to security holders in connection with an annual meeting.

98

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

AMPLIFY ENERGY CORP.

INDEX TO FINANCIAL STATEMENTS

	Page No.
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2017 (Successor Period) and December 31, 2016 (Predecessor Period)	F-3
Statements of Consolidated and Combined Operations for the period from May 5, 2017 through December 31, 2017 (Successor Period), period from January 1, 2017 through May 4, 2017 (Predecessor Period) and the years ended December 31, 2016 and 2015 (Predecessor Period)	F-4
Statements of Consolidated and Combined Cash Flows for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 (Predecessor Period), and the years ended December 31, 2016 and 2015 (Predecessor Period)	F-5
Statements of Consolidated and Combined Equity for the period from May 5, 2017 through December 31, 2017 (Successor Period), the period from January 1, 2017 through May 4, 2017 (Predecessor Period), and the years ended December 31, 2016 and 2015 (Predecessor Period)	F-6
Notes to Consolidated and Combined Financial Statements
Note 1 – Organization and Basis of Presentation	F-8
Note 2 – Emergence from Voluntary Reorganization under Chapter 11	F-9
Note 3 – Fresh Start Accounting	F-10
Note 4 – Summary of Significant Accounting Policies	F-14
Note 5 – Acquisitions and Divestitures	F-20
Note 6 – Fair Value Measurements of Financial Instruments	F-22
Note 7 – Risk Management and Derivative Instruments	F-24
Note 8 – Asset Retirement Obligations	F-26
Note 9 – Restricted Investments	F-26
Note 10 – Debt	F-27
Note 11 – Equity (Deficit)	F-29
Note 12 – Earnings per Share/Unit	F-33
Note 13 – Equity-based Awards	F-33
Note 14 – Related Party Transactions	F-37
Note 15 – Commitments and Contingencies	F-39
Note 16 – Income Tax	F-41
Note 17 – Quarterly Financial Information (Unaudited)	F-44
Note 18 – Supplemental Oil and Gas Information (Unaudited)	F-44
Note 19- Subsequent Events	F-49

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Amplify Energy Corp.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Amplify Energy Corp. and subsidiaries (the Company) as of December 31, 2017 (Successor) and 2016 (Predecessor), the related consolidated statements of operations, equity, and cash flows for the period May 5, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through May 4, 2017, the year ended December 31, 2016 and the related consolidated and combined statements of operations, equity, and cash flows for the year ended 2015 (Predecessor), and the related notes (collectively, the consolidated and combined financial statements). In our opinion, the consolidated and combined financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 (Successor) and 2016 (Predecessor), and the results of its operations and its cash flows for the period May 5, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through May 4, 2017, the years ended December 31, 2016 and 2015 (Predecessor), in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 12, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis of Presentation

As discussed in note 2 to the consolidated and combined financial statements, on April 14, 2017, the United States Bankruptcy Court for the Southern District of Texas entered an order confirming the plan for reorganization, which became effective on May 4, 2017. Accordingly, the accompanying consolidated and combined financial statements have been prepared in conformity with Accounting Standards Codification Topic 852, Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods (Predecessor) as described in note 1.

As discussed in note 1 to the consolidated and combined financial statements, the statements of operations, equity, and cash flows for the year ended December 31, 2015 (Predecessor) have been prepared on a combined basis of accounting.

Basis for Opinion

These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated and combined financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated and combined financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated and combined financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated and combined financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2011.

Houston, Texas

March 12, 2018

F-2

AMPLIFY ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares/units)

	Successor			Predecessor
	December 31,			December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	6,392		$	15,373
Accounts receivable		36,391			34,584
Short-term derivative instruments		28,546			69,464
Prepaid expenses and other current assets		7,220			13,163
Total current assets		78,549			132,584
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		603,053			3,115,012
Support equipment and facilities		100,225			199,093
Other		6,133			15,344
Accumulated depreciation, depletion and impairment		(35,979	)		(1,749,747	)
Property and equipment, net		673,432			1,579,702
Long-term derivative instruments		—			102,630
Restricted investments		156,938			156,234
Other long-term assets		8,545			2,104
Total assets	$	917,464		$	1,973,254
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,941		$	4,353
Revenues payable		22,427			21,285
Accrued liabilities (see Note 4)		18,233			65,235
Current portion of long-term debt (see Note 10)		—			1,622,904
Total current liabilities		42,601			1,713,777
Long-term debt (see Note 10)		376,000			—
Asset retirement obligations		99,460			154,913
Long-term derivative instruments		5,470			—
Deferred tax liabilities		—			2,280
Other long-term liabilities		—			2,795
Total liabilities		523,531			1,873,765
Commitments and contingencies (see Note 15)
Stockholders'/ partners' equity:
Successor preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at December 31, 2017 and 2016, respectively		—			—
Successor warrants, 2,173,913 warrants issued and outstanding at December 31, 2017 and no warrants issued or outstanding at December 31, 2016		4,788			—
Successor common stock, $0.0001 par value: 300,000,000 shares authorized; 25,000,000 shares issued and outstanding at December 31, 2017 and no shares authorized or issued at December 31, 2016		3			—
Successor additional paid-in capital		387,856			—
Successor accumulated earnings (deficit)		1,286			—
Predecessor common units, no units issued or outstanding at December 31, 2017 and 83,827,920 units issued and outstanding at December 31, 2016		—			99,489
Total stockholders'/partners' equity		393,933			99,489
Total liabilities and equity	$	917,464		$	1,973,254

See Accompanying Notes to Consolidated and Combined Financial Statements.

F-3

AMPLIFY ENERGY CORP.

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per share/unit amounts)

	Successor			Predecessor
	Period From			Period from
	May 5, 2017			January 1,			For the Year Ended
	through			2017 through			December 31,
	December 31, 2017			May 4, 2017			2016			2015
Revenues:
Oil and natural gas sales	$	205,176		$	108,970		$	284,051		$	355,422
Other revenues		303			231			529			2,725
Total revenues		205,479			109,201			284,580			358,147
Costs and expenses:
Lease operating expense		74,547			35,568			126,175			168,199
Gathering, processing and transportation		18,652			10,772			34,979			34,939
Exploration		32			21			981			2,317
Taxes other than income		11,101			5,187			15,540			25,828
Depreciation, depletion and amortization		35,979			37,717			171,629			195,814
Impairment of proved oil and natural gas properties		—			—			183,437			616,784
General and administrative expense		29,506			31,606			63,280			56,671
Accretion of asset retirement obligations		4,384			3,407			10,231			7,125
(Gain) loss on commodity derivative instruments		31,609			(23,076	)		117,105			(462,890	)
(Gain) loss on sale of properties		—			—			(2,754	)		(2,998	)
Other, net		485			36			516			(665	)
Total costs and expenses		206,295			101,238			721,119			641,124
Operating income (loss)		(816	)		7,963			(436,539	)		(282,977	)
Other income (expense):
Interest expense, net		(15,936	)		(10,243	)		(146,031	)		(115,154	)
Other income (expense)		16,981			8			8			43
Gain on extinguishment of debt		—			—			42,337			422
Total other income (expense)		1,045			(10,235	)		(103,686	)		(114,689	)
Income (loss) before reorganization items, net and income taxes		229			(2,272	)		(540,225	)		(397,666	)
Reorganization items, net		(1,119	)		(88,774	)		—			—
Income tax benefit (expense)		2,176			91			(173	)		2,175
Net income (loss)		1,286			(90,955	)		(540,398	)		(395,491	)
Net income (loss) attributable to noncontrolling interest		—			—			—			386
Net income (loss) attributable to Successor/Predecessor	$	1,286		$	(90,955	)	$	(540,398	)	$	(395,877	)
Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor	$	1,286		$	(90,955	)	$	(540,398	)	$	(395,877	)
Net (income) loss allocated to previous owners		—			—			—			2,268
Net (income) loss allocated to Predecessor's general partner		—			—			168			327
Net (income) loss allocated to NGP IDRs		—			—			—			(83	)
Net (income) allocated to participating restricted stockholders		(35	)		—			—			—
Net income (loss) available to common stockholders/limited partners	$	1,251		$	(90,955	)	$	(540,230	)	$	(393,365	)
Earnings per share/unit: (See Note 12)
Basic and diluted earnings per share/unit	$	0.05		$	(1.09	)	$	(6.48	)	$	(4.71	)
Weighted average common shares/units outstanding:
Basic and diluted		25,000			83,807			83,351			83,528

See Accompanying Notes to Consolidated and Combined Financial Statements.

F-4

AMPLIFY ENERGY CORP.

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017			For the Year Ended
	through			through			December 31,
	December 31, 2017			May 4, 2017			2016			2015
Cash flows from operating activities:
Net income (loss)	$	1,286		$	(90,955	)	$	(540,398	)	$	(395,491	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		35,979			37,717			171,629			195,814
Impairment of proved oil and natural gas properties		—			—			183,437			616,784
(Gain) loss on derivative instruments		31,609			(23,076	)		118,395			(458,216	)
Cash settlements (paid) received on expired derivative instruments		30,446			15,895			210,704			250,043
Cash settlements (paid) on terminated derivatives		—			94,146			228,646			47,930
Premiums paid for commodity derivatives		—			—			—			(47,930	)
Bad debt expense		—			—			2,050			—
Deferred income tax expense (benefit)		(2,206	)		(74	)		187			(2,234	)
Amortization and write-off of deferred financing costs		2,093			—			22,106			6,058
Amortization and write-off of senior notes discount		—			—			13,185			2,430
Gain on extinguishment of debt		—			—			(42,337	)		(422	)
Accretion of asset retirement obligations		4,384			3,407			10,231			7,125
Gain on sale of properties		—			—			(2,754	)		(2,998	)
Share/unit-based compensation (see Note 13)		2,516			3,667			7,350			10,809
Settlement of asset retirement obligations		(633	)		(164	)		(1,442	)		(1,430	)
Exploration costs		—			—			792			2,078
Reorganization items, net		—			68,356			—			—
Other		—			56			229			—
Changes in operating assets and liabilities:
Accounts receivable		(2,830	)		1,024			23,928			15,528
Prepaid expenses and other assets		5,578			735			(4,088	)		2,275
Payables and accrued liabilities		(13,590	)		15,030			4,084			(32,068	)
Restricted cash		7,561			(7,561	)		—			—
Other		10			(266	)		2,692			666
Net cash provided by operating activities		102,203			117,937			408,626			216,751
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			—			—			(100,730	)
Acquisition post-closing adjustments receipts		—			—			—			9,570
Additions to oil and gas properties		(52,735	)		(6,211	)		(57,675	)		(241,299	)
Additions to other property and equipment		(127	)		(76	)		(7,875	)		—
Additions to restricted investments		(495	)		(209	)		(8,443	)		(5,690	)
Withdrawals of restricted investments		—			—			4,840			—
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold		—			—			52,711			580
Net cash (used in) investing activities		(53,357	)		(6,496	)		(16,442	)		(337,569	)
Cash flows from financing activities:
Advances on revolving credit facilities		9,000			16,600			144,000			562,000
Payments on revolving credit facilities		(63,000	)		(98,252	)		(468,348	)		(138,000	)
Deferred financing costs		(642	)		(8,575	)		(1,350	)		(341	)
Payment to holders of the Notes		(8,193	)		(16,446	)		—			—
Payment to Predecessor common unitholders		(1,250	)		—			—			—
Contribution from management		1,500			—			—			—
Repurchase of senior notes		—			—			(41,261	)		(2,914	)
Capital contributions from previous owners		—			—			—			1,912
Contributions related to sale of assets to NGP affiliate		—			—			26			860
Transfer of operating subsidiary from Memorial Resource		—			—			2,363			—
Proceeds from the issuance of Predecessor common units		—			—			2,385			—
Costs incurred in conjunction with issuance of Predecessor common units		—			—			(536	)		—
Purchase of noncontrolling interest		—			—			—			(5,946	)
Distributions to partners		—			—			(13,300	)		(163,259	)
Distribution to Memorial Resource (see Note 1)		—			—			—			(78,396	)
Acquisition of Predecessor's general partner (see Note 1)		—			—			(750	)		—
Acquisition of incentive distribution rights from NGP (see Note 1)		—			—			(50	)		—
Restricted units returned to plan		—			(10	)		(589	)		(1,285	)
Repurchases under unit repurchase program		—			—			—			(54,184	)
Other		(9	)		9			—			—
Net cash (used in) provided by financing activities		(62,594	)		(106,674	)		(377,410	)		120,447
Net change in cash and cash equivalents		(13,748	)		4,767			14,774			(371	)
Cash and cash equivalents, beginning of period		20,140			15,373			599			970
Cash and cash equivalents, end of period	$	6,392		$	20,140		$	15,373		$	599

See Accompanying Notes to Consolidated and Combined Financial Statements.

See Note 4 for Supplemental Cash Flow information

F-5

AMPLIFY ENERGY CORP.  

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY (PREDECESSOR)

(In thousands)

	Partner's Equity (Deficit)
	Limited Partners
	Common						General			Previous			NGP			Noncontrolling
	Units			Subordinated			Partner			Owners			IDRs			Interest			Total
Balance, December 31, 2014	$	1,085,265		$	(16,419	)	$	1,251		$	220,657		$	—		$	5,560		$	1,296,314
Net income (loss)		(393,395	)		30			(327	)		(2,268	)		83			386			(395,491	)
Contributions (see Note 14)		2,962			—			3			1,912			—			—			4,877
Distributions		(159,975	)		(2,949	)		(252	)		—			(83	)		—			(163,259	)
Distribution attributable to net assets transferred		(78,318	)		—			(78	)		—			—			—			(78,396	)
Net book value of net assets exchanged		250,791			—			251			(248,321	)		—			—			2,721
Purchase of noncontrolling interest		—			—			—			—			—			(5,946	)		(5,946	)
Amortization of equity awards		10,809			—			—			—			—			—			10,809
Conversion of subordinated units to common units		(19,338	)		19,338			—			—			—			—			—
Common units repurchased under repurchase program (see Note 11)		(52,813	)		—			—			—			—			—			(52,813	)
Restricted units repurchased and other		(1,344	)		—			—			—			—			—			(1,344	)
Deferred tax liability retained by previous owner		—			—			—			28,020			—			—			28,020
Balance, December 31, 2015		644,644			—			848			—			—			—			645,492
Net income (loss)		(540,230	)		—			(168	)		—			—			—			(540,398	)
Distributions		(13,289	)		—			(11	)		—			—			—			(13,300	)
Purchase of equity interest of general partner (see Note 1)		(81	)		—			(669	)		—			—			—			(750	)
Acquisition of IDRs from NGP (see Note 1)		(50	)		—			—			—			—			—			(50	)
Net proceeds from issuance of Predecessor common units		1,849			—			—			—			—			—			1,849
Amortization of unit-based awards		7,206			—			—			—			—			—			7,206
Restricted units repurchased and other		(560	)		—			—			—			—			—			(560	)
Balance at December 31, 2016 (Predecessor)		99,489			—			—			—			—			—			99,489
Net income (loss)		(90,955	)		—			—			—			—			—			(90,955	)
Cancellation and amortization of unit-based awards		3,713			—			—			—			—			—			3,713
Restricted units repurchased and other		(2	)		—			—			—			—			—			(2	)
Issuance of common stock to Predecessor common unitholders		(7,707	)		—			—			—			—			—			(7,707	)
Issuance of warrants to Predecessor common unitholders		(4,788	)		—			—			—			—			—			(4,788	)
Contribution from management		1,500			—			—			—			—			—			1,500
Settlement with Predecessor common unitholders		(1,250	)		—			—			—			—			—			(1,250	)
Balance at May 4, 2017 (Predecessor)	$	—		$	—		$	—		$	—		$	—		$	—		$	—

See Accompanying Notes to Consolidated and Combined Financial Statements.

F-6

AMPLIFY ENERGY CORP.

STATEMENTS OF CONSOLIDATED EQUITY (SUCCESSOR)

(In thousands)

	Stockholders' Equity
	Common Stock		Warrants		Additional Paid-in Capital			Accumulated Earnings (Deficit)		Total
Issuance of Successor common stock to holders of the Notes	$	3	$	—	$	377,642		$	—	$	377,645
Issuance of Successor warrants to Predecessor common unitholders		—		4,788		—			—		4,788
Issuance of Successor common stock to Predecessor common unitholders		—		—		7,707			—		7,707
Balance at May 5, 2017 (Successor)		3		4,788		385,349			—		390,140
Net income (loss)		—		—		—			1,286		1,286
Share-based compensation expense		—		—		2,516			—		2,516
Other		—		—		(9	)		—		(9	)
Balance at December 31, 2017 (Successor)	$	3	$	4,788	$	387,856		$	1,286	$	393,933

See Accompanying Notes to Consolidated and Combined Financial Statements.

F-7

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

General

When referring to Amplify Energy Corp. (formerly known as Memorial Production Partners LP and also referred to as “Successor,” “Amplify Energy,” or the “Company”), the intent is to refer to Amplify Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Amplify Energy is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended. When referring to the “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.  

We operate in one reportable segment 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 there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Wyoming and offshore Southern California. 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.

Unless the context requires otherwise, references to: (i) our “Predecessor’s general partner” and “MEMP GP” refers to Memorial Production Partners GP LLC, our Predecessor’s general partner, which was dissolved following the effective date of the Plan; (ii) “Memorial Resource” refers to Memorial Resource Development Corp., the former owner of our Predecessor’s general partner; (iii) “MRD LLC” refers to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively controlled MRD Holdco LLC; (v) “OLLC” refers to Amplify Energy Operating LLC, formerly known as Memorial Production Operating LLC, our wholly owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refers to Memorial Production Finance Corporation, our Predecessor’s wholly owned subsidiary, whose activities were limited to co-issuing our debt securities and engaging in other activities incidental thereto and which was dissolved following the effective date of the Plan; (vii) “MRD Holdco” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource and (viii) “NGP” refers to Natural Gas Partners.

On April 27, 2016, we entered into an agreement pursuant to which the Predecessor agreed to acquire, among other things, all of the equity interests in our Predecessor’s general partner, MEMP GP, from Memorial Resource (the “MEMP GP Acquisition”) for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the incentive distribution rights ("IDRs") in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition.

In connection with the closing of the transactions on June 1, 2016, our Predecessor’s partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Predecessor held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Predecessor will have the ability to elect the members of MEMP GP’s board of directors. In addition, we terminated the Predecessor’s Omnibus Agreement under which Memorial Resource provided management, administrative and operations personnel to us and our Predecessor’s general partner, and we entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 14 for additional information regarding the MEMP GP Acquisition and the transition services agreement.

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer collectively to certain oil and natural gas properties primarily located in East Texas and Louisiana that the Predecessor acquired in February 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”).

The acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisition as if the Predecessor owned the assets for periods after common control commenced through the acquisition date. See Note 14 for additional information.

F-8

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Basis of Presentation

Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements were derived from the historical accounting records of the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented.

The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of Beta Operating Company LLC, was presented as noncontrolling interest in the financial statements for the periods prior to November 3, 2015. On November 3, 2015, we purchased the noncontrolling interest in SPBPC for approximately $6.0 million and completed an acquisition of the remaining interests in our oil and gas properties located offshore Southern California (the “Beta properties”) from a third party for approximately $94.6 million (the “2015 Beta Acquisition”). See Note 5 for additional information regarding the 2015 Beta Acquisition.

All material intercompany transactions and balances have been eliminated in preparation of our Consolidated and Combined Financial Statements. The accompanying Consolidated and Combined Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gain on extinguishment of debt was previously accounted for as interest expense, net and are now being presented as other income (expenses) on our statements of operations on a separate line item.

Bankruptcy Accounting

On January 16, 2017, MEMP and certain of its subsidiaries (collectively with MEMP, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The Debtors operated their business as “debtors-in-possession” under the Bankruptcy Code for the period from January 16, 2017 through May 4, 2017.

The Consolidated and Combined Financial Statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s Statement of Consolidated and Combined Operations.

Comparability of Financial Statements to Prior Periods

As discussed in further detail in Note 3 below, we have adopted and applied the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Consolidated and Combined Financial Statements and Notes after May 4, 2017, are not comparable to the Consolidated and Combined Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Consolidated and Combined Financial Statements and Notes as the “Successor” for periods subsequent to May 4, 2017 and “Predecessor” for periods prior to May 5, 2017. Furthermore, our Consolidated and Combined Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor.

Note 2. Emergence from Voluntary Reorganization under Chapter 11

On January 16, 2017 (the “Petition Date”), the Debtors filed voluntary petitions under the Bankruptcy Code in the Bankruptcy Court to pursue a Joint Chapter 11 Plan of Reorganization for the Debtors. The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262).

On April 14, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) approving the Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (as amended and supplemented, the “Plan”).

On May 4, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and the Company emerged from bankruptcy. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession from January 16, 2017 through May 4, 2017. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.

F-9

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Plan of Reorganization

In accordance with the Plan, on the Effective Date:

• The Successor issued (i) 25,000,000 new shares (the “New Common Shares”) of its common stock, par value $0.0001 per share (“common stock”); and (ii) warrants (the “Warrants”) to purchase up to 2,173,913 shares of the Company’s common stock exercisable for a five-year period commencing on the Effective Date entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding common shares (including common shares as of the Effective Date issuable upon full exercise of the Warrants, but excluding any common shares issuable under the Management Incentive Plan (the “MIP”)), at a per share exercise price of $42.60.

• The holders of claims under the Predecessor’s revolving credit facility received a full recovery, consisting of a cash pay down and their pro rata share of the $1 billion exit senior secured reserve-based revolving credit facility (the “Credit Facility”), as further discussed in Note 10.

• The 7.625% senior notes due May 2021 (“2021 Senior Notes”) and 6.875% senior notes due August 2022 (“2022 Senior Notes” and collectively, the “Notes”) were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received (directly or indirectly) their pro rata share of New Common Shares representing, in the aggregate, 98% of the New Common Shares on the Effective Date (subject to dilution by the MIP and the common shares issuable upon exercise of the Warrants). Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution.

• The Predecessor’s common units were cancelled, and each common unitholder received its pro rata share of: (i) 2% of the New Common Shares, (ii) the Warrants, and (iii) cash in an aggregate amount of approximately $1.3 million.

• The holders of administrative expense claims, priority tax claims, other priority claims and general unsecured creditors of the Predecessor received in exchange for their claims payment in full in cash or otherwise had their rights unimpaired under Title 11 of the United States Code.

• The Successor entered into a stockholders agreement with certain parties pursuant to which the Successor agreed to, at the direction of such stockholders, use commercially reasonable efforts to effect the sale of their common stock.

• The Successor entered into a registration rights agreement with certain parties pursuant to which the Successor agreed to, among other things, file a registration statement with the SEC within 90 days of the receipt of a request from the stockholders party thereto covering the offer and resale of the common stock held by such stockholders.

• The Company’s MIP became effective, such that an aggregate of 2,322,404 shares of the Company’s common stock are available for grant pursuant to awards under the MIP.

• The terms of the Predecessor’s general partner’s board of directors automatically expired on the Effective Date. The Successor formed a new seven-member board of directors consisting of the President and Chief Executive Officer, one director of the Predecessor, and five new members designated by certain parties to the plan support agreement.

Note 3. Fresh Start Accounting

Upon emergence from the Chapter 11 proceedings on May 4, 2017, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims.

Reorganization Value

The Successor’s enterprise value, as approved by the Bankruptcy Court, was estimated to be within a range of $700 million to $900 million, with a midpoint estimate of approximately $800 million. Enterprise value represents the estimated fair value of a company’s interest-bearing debt and its shareholders’ equity. Based on the estimates and assumptions utilized in our fresh start accounting process, we estimated the Successor’s enterprise value to be approximately $800 million before the consideration of cash and cash equivalents on hand at the Effective Date. Reorganization value represents the fair value of the Successor’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value, which was derived from the Successor’s enterprise value, was allocated to our individual assets based on their estimated fair values.

F-10

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The following table is a reconciliation of the enterprise value to the reorganization value of the Successor assets at the Effective Date (in thousands):

Enterprise value	$	800,000
Plus: Cash and cash equivalents		20,140
Plus: Other working capital liabilities		63,817
Plus: Other long-term liabilities		97,470
Reorganization value of Successor assets	$	981,427

Our assets consist primarily of producing oil and natural gas properties. The fair values of proved and unproved oil and natural gas properties were estimated using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with NYMEX forward curve pricing and is adjusted for estimated location and quality differentials, as well as other factors as necessary that the Company’s management believes will impact realizable prices. The fair value of support equipment and facilities were estimated using a cost approach, based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets.

See below under the caption “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of the Company’s various other significant assets and liabilities.

F-11

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Condensed Consolidated Balance Sheet

The adjustments included in the following condensed consolidated balance sheet reflect the effect of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions.  

	As of May 4, 2017
			Reorganization				Fresh Start
	Predecessor		Adjustments (1)				Adjustments				Successor
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	83,050	$	(62,910	)	(2)	$	—			$	20,140
Restricted cash		—		7,411		(3)		—				7,411
Accounts receivable		33,560		—				—				33,560
Short-term derivative instruments		51,329		—				—				51,329
Prepaid expenses and other current assets		10,229		675		(4)		—				10,904
Total current assets		178,168		(54,824	)			—				123,344
Property and equipment, net		1,551,500		—				(894,164	)	(11)		657,336
Long-term derivative instruments		33,800		—				—				33,800
Restricted investments		156,443		—				—				156,443
Other long-term assets		1,929		8,575		(5)		—				10,504
Total assets	$	1,921,840	$	(46,249	)		$	(894,164	)		$	981,427
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,501	$	1,389		(6)	$	—			$	2,890
Revenues payable		22,747		—				—				22,747
Accrued liabilities		36,954		2,939		(7)		(1,713	)	(12)		38,180
Current portion of long-term debt		454,799		(454,799	)	(8)		—				—
Total current liabilities		516,001		(450,471	)			(1,713	)			63,817
Liabilities subject to compromise		1,162,437		(1,162,437	)	(9)		—				—
Long-term debt		—		430,000		(8)		—				430,000
Asset retirement obligations		158,114		—				(62,928	)	(13)		95,186
Deferred tax liabilities		2,206		—				—				2,206
Other long-term liabilities		2,481		—				(2,403	)	(12)		78
Total liabilities		1,841,239		(1,182,908	)			(67,044	)			591,287
Commitments and contingencies (see Note 14)
Stockholders'/partners' equity:
Predecessor common units		80,601		(80,601	)	(10)		—				—
Successor warrants		—		4,788		(10)		—				4,788
Successor common stock		—		3		(10)		—				3
Successor additional paid-in capital		—		1,212,469		(10)		(827,120	)	(14)		385,349
Total stockholders'/ partners' equity		80,601		1,136,659				(827,120	)			390,140
Total liabilities and equity	$	1,921,840	$	(46,249	)		$	(894,164	)		$	981,427

Reorganization Adjustments

(1) Reflects amounts recorded as of the Effective Date for the implementation of the Plan, including among other items, settlement of the Predecessor’s liabilities subject to compromise, cancellation of the Predecessor’s equity, issuance of the Successor New Common Shares and the Warrants, repayment of certain of Predecessor’s debt and settlement with holders of the Notes.

F-12

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(2) Reflects the changes in cash and cash equivalents, including the following (in thousands):

Payment on the Predecessor's revolving credit facility	$	(24,799	)
Payment to holders of the Notes (1)		(16,446	)
Payment of fees related to Credit Facility		(8,575	)
Funding of the professional fees escrow account		(7,411	)
Payment of professional fees		(4,295	)
Other		(1,384	)
Changes in cash and cash equivalents	$	(62,910	)

(1) The total cash settlement to the holders of the Notes was approximately $24.6 million, of which $16.4 million was paid upon emergence and $8.2 million was paid post-emergence and is reflected in accrued liabilities in the above condensed consolidated balance sheet.

(3) Reflects the transfer to restricted cash to fund the professional fees escrow account.

(4) Reflects the pre-payment of certain professional fees.

(5) Reflects the deferred financing costs related to the Credit Facility.

(6) Reflects the recognition of payables for general unsecured claims.

(7) Net increase in accrued liabilities reflects the following (in thousands):

Recognition of liability for settlement with holders of the Notes	$	8,193
Payment of professional fees		(4,295	)
Recognition of contribution from management		(1,500	)
Recognition of settlement with Predecessor common unitholders		1,250
Other		(709	)
Net increase in accrued liabilities due to reorganization items	$	2,939

(8) Reflects a repayment of $24.8 million on the Predecessor’s revolving credit facility and the reclassification of $430.0 million in borrowings under the Credit Facility to long-term debt.

(9) Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands):

Accounts payable	$	1,389
Accrued interest payable		49,796
Debt		1,111,252
Total liabilities subject to compromise of Predecessor		1,162,437
Recognition of payables for general unsecured claims		(1,389	)
Recognition of settlement with holders of the Notes		(24,639	)
Issuance of common stock to holders of the Notes		(377,645	)
Gain on settlement of liabilities subject to compromise	$	758,764

(10) Net increase in our stockholders’/partners’ equity reflects the following (in thousands):

Issuance of common stock to holders of the Notes	$	377,645
Issuance of common stock to Predecessor common unitholders		7,707
Cancellation of the Predecessor's units issued and outstanding		80,601
Recognition on gain on settlement of liabilities subject to compromise		758,764
Recognition of issuance of common stock to Predecessor common unitholders		(7,707	)
Recognition of issuance of warrants to Predecessor common unitholders		(4,788	)
Recognition of contribution from management		1,500
Recognition of settlement with Predecessor common unitholders		(1,250	)
Par value of common stock		(3	)
Change in Successor additional paid-in capital		1,212,469
Issuance of warrants to Predecessor common unitholders		4,788
Par value of common stock		3
Predecessor units issued and outstanding		(80,601	)
Net increase in capital accounts	$	1,136,659

F-13

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Fresh Start Adjustments

(11) Reflects a decrease of property and equipment, net based on the methodology discussed above and the elimination of accumulated depreciation, depletion and impairment. The fresh start adjustments to property and equipment, net are as follow:

	Predecessor			Fresh Start Adjustments			Successor
	(In thousands)
Property and equipment at cost:
Proved oil and natural gas properties	$	3,124,137		$	(2,615,076	)	$	509,061
Support equipment and facilities		199,463			(101,883	)		97,580
Unproved oil and natural gas properties		—			44,688			44,688
Other		15,420			(9,413	)		6,007
Property and equipment		3,339,020			(2,681,684	)		657,336
Accumulated depreciation, depletion and impairment		(1,787,520	)		1,787,520			—
Property and equipment, net	$	1,551,500		$	(894,164	)	$	657,336

(12) Reflects the write-off of the deferred rent and loss on sublease liabilities.

(13) Reflects a decrease of $62.9 million for asset retirement obligations. The fair value of asset retirement obligations were estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk free rate.

(14) Reflects the cumulative impact of our fresh start accounting adjustments discussed above.

Reorganization Items, Net

The Company has incurred significant costs associated with the reorganization. These costs, which are expensed as incurred, were expected to significantly affect the Company’s results of operations. Reorganization items, net represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date.

The following table summarizes the components of reorganization items, net included in the accompanying Statements of Consolidated and Combined Operations (in thousands):

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1,
	through			2017 through
	December 31, 2017			May 4, 2017
Gain on settlement of liabilities subject to compromise	$	—		$	758,764
Fresh start valuation adjustments		—			(827,120	)
Professional fees		(724	)		(19,824	)
Other		(395	)		(594	)
Reorganization items, net	$	(1,119	)	$	(88,774	)

Note 4. Summary of Significant Accounting Policies

Fresh Start Accounting

Upon the Effective Date, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims. Fresh start accounting involved a comprehensive valuation process in which we determined the fair value of all of our assets and liabilities on the Effective Date. See Note 3 for additional information.

Use of Estimates

The preparation of Consolidated and Combined Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated and Combined Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

F-14

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Principles of Consolidation and Combination

Our consolidated financial statements include our accounts and those of our majority-owned subsidiary in which we have a controlling interest and acquired the remaining interests on November 3, 2015, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of the previous owners as discussed above in Note 1. All material intercompany balances and transactions have been eliminated.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

Concentrations of Credit Risk

Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts which are held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, individuals and others who own interests in the properties operated by us. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. We recorded $1.9 million as an allowance for doubtful accounts at December 31, 2017 and 2016, respectively.

If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, seismic costs and delay rental payments attributable to unproved locations are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Support equipment and facilities, which are primarily related to our Wyoming and California assets, are depreciated using the straight-line method generally based on estimated useful lives of twelve to twenty-four years.

F-15

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2017 and 2016.

Oil and Natural Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the Consolidated and Combined Financial Statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2017.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property & Equipment

Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years.

Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense, net in the statement of operations. These restricted investments may consist of money market deposit accounts and U.S. Government securities. See Note 9 for additional information.

Debt Issuance Costs

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the period from May 5, 2017 through December 31, 2017 and the years ended December 31, 2016 and 2015 was approximately $2.1 million, $22.1 million, and $6.1 million, respectively. No amortization of deferred financing cost was recorded for the period from January 1, 2017 through May 4, 2017 as the unamortized amount of deferred financing cost at December 31, 2016 was written off due to (i) the uncertainty regarding the Predecessor’s ability to cure the default that existed at December 31, 2016, (ii) the Predecessor’s inability to comply with certain financial covenants contained in our Predecessor’s revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. No impairment expense was recorded for the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017. Impairment expense for the years ended December 31, 2016 and 2015 was approximately $183.4 million and $616.8 million, respectively.

F-16

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses. We did not record any impairments related to unproved properties for the year ended December 31, 2017, 2016 and 2015.

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 8 for further discussion of asset retirement obligations.

Book Overdrafts

Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2017 and 2016.

The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:

	Successor	Predecessor
	Period from	Period from
	May 5, 2017	January 1, 2017
	through	through	For the Year Ending December 31,
	December 31, 2017	May 4, 2017	2016	2015
Major customers:
Phillips 66	23%	19%	19%	12%
Sinclair Oil & Gas Company	19%	20%	16%	18%
CIMA Energy	11%	n/a	n/a	n/a
BP America Production Company	10%	10%	n/a	n/a
Royal Dutch Shell plc and subsidiaries	n/a	n/a	14%	14%

General and Administrative Expense

Prior to June 1, 2016, Memorial Resource provided management, administrative and operating services to the Predecessor and our Predecessor’s general partner pursuant to our Predecessor’s Omnibus Agreement. Upon completion of the MEMP GP Acquisition, the Predecessor’s Omnibus Agreement was terminated on June 1, 2016, and the Predecessor entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. Prior to the MEMP GP Acquisition, our Predecessor’s partnership agreement provided that our Predecessor’s general partner determined in good faith the expenses that were allocated to us, including expenses incurred by our Predecessor’s general partner and its former affiliates on our behalf. Memorial Resource allocated indirect general and administrative costs based on time allocations for the three months ended March 31, 2016 and the year ended December 31, 2015 and based on the terms as set forth by the MEMP GP Acquisition purchase and sale agreement for the period from April 1, 2016 through the closing date. Under our Predecessor’s partnership agreement and the Predecessor’s Omnibus Agreement, we reimbursed Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 14 for additional information regarding the Predecessor’s Omnibus Agreement.

General and administrative expenses associated with the previous owners included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production.

F-17

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps) are used to reduce the impact of natural gas and oil price fluctuations. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. For the period from May 5, 2017 through December 31, 2017 and the years ended December 31, 2016 and 2015, we had $0.4 million, $0.5 million and $2.1 million in capitalized interest, respectively. No capitalized interest recorded for the period from January 1, 2017 through May 4, 2017.

Income Tax

We are a corporation subject to federal and certain state income taxes. Our Predecessor was organized as a pass-through entity for federal and most state income tax purposes. Certain of our consolidated subsidiaries were taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax for activity in the state of Texas.

We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our Statement of Consolidated and Combined Operations.

We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination by taxing authorities, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. Although we believe our assumptions, judgements and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The provisions of the Tax Act that impact us include, but are not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) temporary bonus depreciation that will allow for full expensing of qualified property, and (4) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80 percent of taxable income.

Earnings Per Share/Unit

Basic and diluted earnings per share/unit (“EPS” or “EPU”) is determined by dividing net income or loss available to the common stockholders/limited partners by the weighted average number of outstanding shares/units during the period. Diluted earnings (loss) per common share is calculated under the two-class method and the treasury stock method by dividing net income (loss) available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. Net income or loss available to the Predecessor limited partners was determined by applying the two-class method. The two-class method of computing the Predecessor’s EPU was an earnings allocation formula that determined EPU based on distributions declared. The amount of net income or loss used in the determination of EPU was reduced (or increased) by the amount of available cash that had been distributed to the Predecessor’s limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings were allocated to the Predecessor’s limited partners in accordance with the contractual terms of the Predecessor’s partnership agreement. The total earnings allocated to the Predecessor’s limited partners was determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participated in distributions. See Note 12 for additional information.

F-18

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Equity Compensation

The fair value of equity-classified awards (e.g., restricted common unit awards, restricted stock units or stock options) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom units awards) are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. We currently have no awards subject to performance criteria; however, such awards would vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 13 for further information.

Accrued Liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

	Successor		Predecessor
	December 31,		December 31,
	2017		2016
Accrued lease operating expense	$	6,439	$	10,411
Accrued general and administrative expense		4,412		3,040
Accrued capital expenditures		3,854		1,826
Accrued interest payable		1,309		46,417
Asset retirement obligation		713		789
Accrued ad valorem tax		398		977
Other		1,108		1,775
Accrued liabilities	$	18,233	$	65,235

Supplemental Cash Flows

Supplemental cash flow for the periods presented (in thousands):

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017		For the Year Ended
	through			through		December 31,
	December 31, 2017			May 4, 2017		2016			2015
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	12,109		$	6,598	$	87,527		$	107,272
Cash paid for reorganization items, net		7,934			11,999		—		$	—
Cash paid for taxes		—			—		—			472
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(1,080	)		3,173		(6,284	)		(27,932	)
(Increase) decrease in accounts receivable related to acquisitions		—			—		—			9,698
(Increase) decrease in accounts receivable/payable related to divestitures		—			—		(289	)		—
Assumptions of asset retirement obligations related to acquisitions		—			—		—			23,754
Asset retirement obligation removal related to divestitures		—			—		(19,669	)		—

New Accounting Pronouncements

Compensation—Stock Compensation. In May 2017, the FASB issued an accounting standards update to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance in the terms and conditions of a share-based payment award. The new guidance is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures.

Definition of a Business. In January 2017, the FASB issued an accounting standards update to clarify the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments provide a more robust framework to use in determining when a set of assets and activities is a business. The amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures.

F-19

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force. In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures.

Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures.

Leases. In February 2016, the FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term.

The Company is the lessee under various agreements for office space, compressors, equipment, and surface rentals that are currently accounted for as operating leases, refer to Note 15, Commitments and Contingencies. As a result, these new rules will increase reported assets and liabilities. The Company will not early adopt this standard. The Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using a modified retrospective approach, including several optional practical expedients related to leases commenced before the effective date. The Company is currently evaluating the impact of these rules on its financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The adoption of this standard will result in an increase in the assets and liabilities on the Company’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods.

Revenue from Contracts with Customers. In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The guidance is effective for interim and annual reporting periods starting January 1, 2018, and early adoption is permitted. The Company adopted this guidance as of January 1, 2018 and plans to use the modified retrospective approach, with the cumulative effect of initial application recognized at the date of initial application subject to certain additional disclosures. The Company has performed a detailed review of key contracts and based on that review has concluded the adoption of this new accounting standard will not have a material impact on the consolidated financial statements and related footnote disclosures.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Note 5. Acquisitions and Divestitures

The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through capital contributions and borrowings under our Predecessor’s revolving credit facility.

F-20

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

The Predecessor had consummated several common control acquisitions since completing its IPO in December 2011, as further discussed in Note 14, directly or indirectly from Memorial Resource and certain affiliates of NGP.

Acquisition and Divestiture related expenses

Acquisition and divestiture related expenses for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

Successor		Predecessor
Period from		Period from
May 5, 2017		January 1, 2017		For the Year Ended
through		through		December 31,		December 31,
December 31, 2017		May 4, 2017		2016		2015
$	609	$	—	$	1,451	$	1,928

2015 Acquisitions

2015 Beta Acquisition. On November 3, 2015, we closed the 2015 Beta Acquisition, which included the acquisition of the noncontrolling interest in SPBPC for approximately $6.0 million and the acquisition of the remaining interests in our oil and gas properties located offshore Southern California from a third party for approximately $94.6 million. During the year ended December 31, 2015, we recorded revenues of $3.6 million in the statement of operations and generated losses of approximately $1.0 million related to the 2015 Beta Acquisition subsequent to the closing date. The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the 2015 Beta Acquisition (in thousands):

	Predecessor
	2015 Beta
	Acquisition
Oil and gas properties	$	40,029
Prepaid expenses and other current assets		840
Restricted investments		69,579
Derivative instruments		4,568
Accounts receivable - affiliates and other		4,499
Asset retirement obligations		(22,871	)
Accrued liabilities		(2,010	)
Total identifiable net assets	$	94,634

The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Predecessor and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired (iii) accretion expense associated with asset retirement obligations recorded and (iv) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	Predecessor
	For the Year Ended
	December 31, 2015
(In thousands, except per unit amounts)
Revenues	$	381,495
Net income (loss)		(394,756	)
Basic and diluted earnings per unit		(4.73	)

2016 Divestitures

On July 14, 2016, we closed a transaction to divest certain assets located in Colorado and Wyoming (the “Rockies Divestiture”) to a third party for total proceeds of approximately $16.4 million, including final post-closing adjustments. We recorded a loss of approximately $4.2 million in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our Predecessor’s revolving credit facility. This disposition did not qualify as a discontinued operation.

F-21

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

On June 14, 2016, we closed a transaction to divest certain assets located in the Permian Basin (the “Permian Divestiture”) to a third party for a total purchase price of approximately $36.7 million including estimated post-closing adjustments, which included $36.4 million in cash and $0.3 million in accounts receivable at December 31, 2016. We recognized a gain of $6.1 million on the sale of properties related to the Permian Divestiture in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our Predecessor’s revolving credit facility. This disposition did not qualify as a discontinued operation.

During the year ended December 31, 2016, the Predecessor completed other immaterial divestitures for less than $0.1 million for which we recorded a gain of $0.9 million on the sale that is recorded in “(gain) loss on sale of properties” in the accompanying statement of operations.

The income (loss) before income taxes, including the associated (gain) loss on sale of properties, related to the Permian Divestiture and Rockies Divestiture included in the Statements of Consolidated and Combined Operations of the Company is as follows (in thousands):

	Predecessor
	For the Year Ended December 31,
	2016			2015
Permian Divestiture	$	4,297		$	(60,875	)
Rockies Divestiture		(7,677	)		(56,917	)

2015 Divestitures

During the year ended December 31, 2015, we conducted an auction process administered by a third-party and sold interests in certain oil and gas properties located in the Permian Basin in various Texas and New Mexico counties to two third parties for approximately $0.6 million in the aggregate. In addition as part of that auction process, we also sold interests in certain oil and gas properties located in the Permian Basin to a related party for approximately $0.9 million. See Note 14 for additional information regarding this related party divestiture.

Note 6. Fair Value Measurements of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2017 and 2016, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2017 and December 31, 2016. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 10 for the estimated fair value of our outstanding fixed-rate debt.

F-22

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2017 and December 31, 2016 were based on estimated forward commodity prices (including nonperformance risk). Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 and December 31, 2016 for each of the fair value hierarchy levels:

	Successor
	Fair Value Measurements at December 31, 2017 Using
	Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	38,188	$	—	$	38,188
Liabilities:
Commodity derivatives	$	—	$	15,112	$	—	$	15,112

	Predecessor
	Fair Value Measurements at December 31, 2016 Using
	Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	189,851	$	—	$	189,851
Liabilities:
Commodity derivatives	$	—	$	17,757	$	—	$	17,757

See Note 7 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:

• The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 8 for a summary of changes in AROs.

• If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations is commonly estimated using the depreciated replacement cost approach.

• Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

(i) No impairments was recognized for the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017.

F-23

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(ii) During the year ended December 31, 2016, we recognized $183.4 million of impairments related to certain properties in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices and change in future planned development due to liquidity constraints as a result of our Predecessor’s reduced borrowing base during the three months ended December 31, 2016. As a result of the impairments, the carrying value of these properties was reduced to approximately $156.2 million.

(iii) During the year ended December 31, 2015, we recognized $616.8 million of impairments. These impairments primarily related to certain properties located in East Texas, South Texas, the Permian Basin, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties was reduced to approximately $408.6 million.

Note 7. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production. These transactions limit exposure to declines in prices, but also limit the benefits that would be realized if prices increase.

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2017, after taking into effect netting arrangements, we had no counterparty exposure related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $26.5 million against amounts outstanding under our Credit Facility at December 31, 2017. See Note 10 for additional information regarding our Credit Facility.

Commodity Derivatives

A combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and basis swaps) is used to manage exposure to commodity price volatility.

In January 2017, in connection with our restructuring efforts, we monetized $94.1 million in commodity hedges and used a portion of the proceeds to reduce the amounts outstanding under our Predecessor’s revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes.

In December 2016, in connection with our restructuring efforts, we monetized approximately $191.4 million in commodity hedges and used the proceeds to reduce amounts outstanding under our Predecessor’s revolving credit facility.

During the periods of April through June 2016, we monetized approximately $39.3 million in commodity hedges and used the proceeds from the settlements to repurchase senior notes.

We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub. We also enter into oil derivative contracts indexed to either NYMEX WTI or Inter-Continental Exchange (“ICE”) Brent. Our NGL derivative contracts are indexed to OPIS Mont Belvieu.

F-24

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

At December 31, 2017, the Company had the following open commodity positions:

	2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (MMBtu)		1,102,000		300,000
Weighted-average fixed price	$	3.91	$	2.91
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		152,000		110,000
Weighted-average fixed price	$	71.31	$	51.34
NGL Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		65,700		—
Weighted-average fixed price	$	24.13	$	—

Interest Rate Swaps

Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. The Company did not have any interest rate swaps at December 31, 2017.

During December 2016, in connection with our restructuring efforts, we elected to terminate the interest rate swaps associated with our Predecessor’s revolving credit facility and in the aggregate paid our counterparties approximately $2.1 million. The Predecessor did not have any interest rate swaps at December 31, 2016.

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2017 and 2016. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.

		Successor						Predecessor
		Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
		December 31,			December 31,			December 31,			December 31,
Type	Balance Sheet Location	2017			2017			2016			2016
		(In thousands)						(In thousands)
Commodity contracts		$	37,729		$	9,183		$	86,335		$	16,871
Gross fair value			37,729			9,183			86,335			16,871
Netting arrangements			(9,183	)		(9,183	)		(16,871	)		(16,871	)
Net recorded fair value	Short-term derivative instruments	$	28,546		$	—		$	69,464		$	—
Commodity contracts		$	459		$	5,929		$	103,515		$	885
Gross fair value			459			5,929			103,515			885
Netting arrangements			(459	)		(459	)		(885	)		(885	)
Net recorded fair value	Long-term derivative instruments	$	—		$	5,470		$	102,630		$	—

F-25

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):

	Successor		Predecessor
	Period from		Period from
	May 5, 2017		January 1, 2017			For the Year Ended
Statements of	through		through			December 31,
Operations Location	December 31, 2017		May 4, 2017			2016		2015
(Gain) loss on commodity derivatives	$	31,609	$	(23,076	)	$	117,105	$	(462,890	)
Interest expense, net		—		—			1,290		4,674

Note 8. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the Company’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015 (in thousands):

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017			For the Year Ended
	through			through			December 31,
	December 31, 2017			May 4, 2017			2016			2015
Asset retirement obligations at beginning of period	$	96,127		$	155,702		$	164,164		$	112,702
Liabilities added from acquisition or drilling		191			6			30			26,876
Liabilities removed upon sale of wells		—			—			(19,669	)		(3,412	)
Liabilities settled		(633	)		(164	)		(1,442	)		(1,430	)
Accretion expense		4,384			3,407			10,231			7,125
Revision of estimates		104			104			2,388			22,303
Asset retirement obligation at end of period		100,173			159,055			155,702			164,164
Fresh start adjustment (1)		—			(62,928	)		—			—
Less: Current Portion		713			941			789			1,175
Asset retirement obligations - long-term portion	$	99,460		$	95,186		$	154,913		$	162,989

(1) As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligation at fair value as of the Effective date.

Note 9. Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. During 2016, we replaced certain restricted investments with surety bonds. The components of the restricted investment balances are as follows:

	Successor		Predecessor
	December 31,		December 31,
	2017		2016
	(In thousands)
BOEM platform abandonment (See Note 15)	$	152,272	$	152,000
Surety bond cash collateral		501		500
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		4,058		3,627
Port of Long Beach pipeline license		107		107
Restricted investments	$	156,938	$	156,234

F-26

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 10. Debt

Our consolidated debt obligations consisted of the following at the dates indicated:

	Successor		Predecessor
	December 31,		December 31,
	2017		2016
	(In thousands)
Successor $1.0 billion Credit Facility, variable-rate, due March 2021 (1)	$	376,000	$	—
Predecessor $2.0 billion revolving credit facility, variable-rate, due March 2018 (1)		—		511,652
2021 Senior Notes, fixed-rate, due May 2021 (2) (4)		—		646,287
2022 Senior Notes, fixed-rate, due August 2022 (3) (4)		—		464,965
Total debt		376,000		1,622,904
Less: current portion of long-term debt (5)		—		(1,622,904	)
Long-term debt	$	376,000	$	—

(1) The carrying amount of our Predecessor’s revolving credit facility and Successor Credit Facility approximates fair value because the interest rates are variable and reflective of market rates.

(2) The estimated fair value of our 2021 Senior Notes was $314.3 million at December 31, 2016.

(3) The estimated fair value of our 2022 Senior Notes was $223.2 million at December 31, 2016.

(4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(5) Due to an existing and anticipated financial covenant violations, the Predecessor’s revolving credit facility and senior notes were classified as current at December 31, 2016. There were no existing or anticipated financial covenant violations as of December 31, 2017.

Credit Facility

On May 4, 2017, OLLC, as borrower, entered into the Amended and Restated Credit Agreement (the “Credit Agreement”) among Amplify Acquisitionco Inc., a Delaware corporation (“Acquisitionco”), as parent guarantor, the lenders from time to time party thereto and Wells Fargo Bank, National Association, as Administrative Agent. Pursuant to the Credit Agreement the lenders party thereto agreed to provide OLLC with the Credit Facility (the loans thereunder, the “Loans”). The aggregate principal amount of Loans outstanding under the Credit Facility as of the Effective Date was $430.0 million.

The terms and conditions under the Credit Agreement include (but are not limited to) the following:

• a borrowing base of approximately $490.0 million (which borrowing base amount will be reduced by $2.5 million each month until the next scheduled redetermination of the borrowing base to occur in November 2017);

• a maturity date of March 19, 2021 for the Credit Facility;

• the Loans shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 2.00% to 3.00% or (ii) adjusted LIBOR plus an applicable margin of 3.00% to 4.00%, in each case based on the borrowing base utilization percentage under the Credit Facility;

• the unused commitments under the Credit Facility will accrue a commitment fee of 0.50%, payable quarterly in arrears;

• the obligations under the Credit Agreement are guaranteed by Acquisitionco and substantially all of OLLC’s subsidiaries (the “Guarantors”), subject to limited exceptions, and secured on a first-priority basis by substantially all of OLLC’s and the Guarantors’ assets, including, without limitation, liens on at least 95% of the total value of OLLC’s and the Guarantors’ oil and gas properties, a non-recourse pledge by the Company of the capital stock of Acquisitionco, a pledge by Acquisitionco of the membership interests of OLLC and pledges of stock of all other direct and indirect subsidiaries of OLLC, subject to certain limited exceptions;

• certain financial covenants, including the maintenance of (i) an interest coverage ratio not to exceed 2.50 to 1.00, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending, commencing with the fiscal quarter ending September 30, 2017, (ii) a current ratio, determined as of the last day of each fiscal quarter, commencing with the fiscal quarter ending September 30, 2017, of not less than 1.00 to 1.00 and (iii) a total leverage ratio, determined as of the last day of each fiscal quarter, commencing with the fiscal quarter ending September 30, 2017, of less than or equal to 4.00 to 1.00;

• a hedging requirement of 50% of reasonably anticipated projected production of hydrocarbons from proved developed producing reserves for each calendar month during 2018; and

F-27

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

• certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

First Amendment to Credit Facility

On November 30, 2017, we entered into the first amendment to our Credit Agreement. The first amendment, among other things, amended the Credit Agreement to:

• reflect the reduction of the borrowing base under the Credit Facility from $475.0 million to $450.0 million, effective as of November 30, 2017, with the borrowing base to be automatically reduced by $2.5 million each month until the next scheduled redetermination of the borrowing base to occur on or about April 2018;

• remove the requirement to make mandatory prepayments of borrowings in respect of excess unrestricted cash and cash equivalents greater than $35.0 million; and

• increase the hedging requirement from 50% to 75% of reasonably anticipated projected production of hydrocarbons from proved developed producing reserves for each calendar month for 2018 and 2019 and extended the deadline for entry into such hedging arrangements from December 31, 2017 to April 30, 2018.

The borrowing base for our Credit Facility was $447.5 million at December 31, 2017. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base.

Predecessor’s Revolving Credit Facility

Our Predecessor was a party to a $2.0 billion revolving credit facility, which was guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries).

On the Effective Date of the Plan, the holders of claims under the Predecessor’s revolving credit facility received a full recovery, which included a $24.8 million pay down and their pro rata share of the Credit Facility. See Note 2 for additional information.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented:

	Successor	Predecessor
	Period from	Period from
	May 5, 2017	January 1, 2017	For the Year Ended
	through	through	December 31,
	December 31, 2017	May 4, 2017	2016	2015
Successor Credit Facility	5.08%	n/a	n/a	n/a
Predecessor's revolving credit facility	n/a	4.18%	3.28%	2.12%

Senior Notes

On April 17, 2013, May 23, 2013 and October 10, 2013, our Predecessor and Finance Corp.’s (collectively, the “Issuers”) issued $300.0 million, $100.0 million and $300.0 million, respectively, the 2021 Senior Notes. The 2021 Senior Notes were fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain subsidiaries of the Predecessor. The 2021 Senior Notes would have matured on May 1, 2021 with interest accruing at a rate of 7.625% per annum and was payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes were governed by an indenture and were subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any.

On July 17, 2014, the Issuers completed a private placement of $500.0 million aggregate principal amount of the 2022 Senior Notes. The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Predecessor. The 2022 Senior Notes would have matured on August 1, 2022 with interest accruing at 6.875% per annum and was payable semi-annually in arrears on February 1 and August 1 of each year, commencing February 1, 2015. The 2022 Senior Notes were governed by an indenture and were subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any.

F-28

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

During the year ended December 31, 2016, the Predecessor repurchased on the open market an aggregate principal amount of approximately $53.7 million of its 2021 Senior Notes. In connection with the repurchases, the Predecessor paid approximately $26.4 million and recorded a gain of $27.5 million.

During the year ended December 31, 2016, the Predecessor repurchased on the open market an aggregate principal amount of $32.0 million of its 2022 Senior Notes. In connection with the repurchases, the Predecessor paid approximately $14.9 million and recorded a gain of $14.8 million. During the year ended December 31, 2015, the Predecessor repurchased on the open market approximately $3.0 million of its 2022 Senior Notes. In connection with the repurchase, the Predecessor paid approximately $2.9 million and recorded a gain on extinguishment of debt of approximately $0.4 million.

The Company’s voluntary petitions as described in Note 2 constituted an event of default that accelerated the obligations under the Notes. For the period from January 17, 2017 through May 4, 2017 our contractual interest that was not recorded on the Notes was approximately $24.2 million.

On the Effective Date, the Notes were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received their pro rata share of the New Common Shares. Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution.

Letters of credit

At December 31, 2017, we had $2.4 million letters of credit outstanding, all related to operations at our Wyoming properties.

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with our Credit Facility was $7.1 million at December 31, 2017. The unamortized deferred financing costs are amortized over the remaining life of our Credit Facility using the straight-line method which generally approximate the effective interest method.

At December 31, 2016, there were no remaining unamortized deferred financing costs as approximately $1.3 million in deferred financing fees were written off related to our Predecessor’s revolving credit facility, approximately $8.5 million were written off for the 2021 Senior Notes and approximately $5.7 million were written off for the 2022 Senior Notes due to a default and event of default and the uncertainty regarding anticipated financial covenant violations at December 31, 2016.

Note 11. Equity (Deficit)

Issuance of Common Stock and Cancellation of Units

In accordance with the Plan, on the Effective Date:

• the Company issued 25,000,000 New Common Shares and Warrants to purchase up to 2,173,913 shares of its common stock;

• the Predecessor common units were cancelled; and

• each Predecessor common unitholder received its pro rata share of: (i) 2% of the New Common Shares, (ii) the Warrants, and (iii) cash in an aggregate amount of approximately $1.3 million.

On the Effective Date, there were 25,000,000 New Common Shares issued and outstanding.

F-29

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Equity Outstanding

The following table summarizes the changes in the number of outstanding common units and shares of common stock:

	Common						General
	Units/Shares			Subordinated			Partner
Balance, December 31, 2014 (Predecessor)		80,421,992			5,360,912			86,797
Restricted common units issued		827,704			—			—
Restricted common units forfeited		(69,059	)		—			—
Restricted common units repurchased (1)		(87,228	)		—			—
Common units repurchased under repurchase program		(3,547,921	)		—			—
Subordinated units converted to common units		5,360,912			(5,360,912	)		—
Balance, December 31, 2015 (Predecessor)		82,906,400			—			86,797
Common units issued		1,178,102			—			—
Restricted common units issued		50,000			—			—
Restricted common units forfeited		(27,537	)		—			—
Restricted common units repurchased (1)		(279,045	)		—			—
Cancellation of general partner units		—			—			(86,797	)
Balance, December 31, 2016 (Predecessor)		83,827,920			—			—
Restricted common units issued		—			—			—
Restricted common units forfeited		(12,952	)		—			—
Restricted common units repurchased (1)		(14,681	)		—			—
Balance, May 4, 2017 (Predecessor)		83,800,287			—			—
Cancellation of Predecessor common units		(83,800,287	)		—			—
Balance, May 4, 2017 (Predecessor)		—			—			—
Issuance of Successor common stock		25,000,000			—			—
Balance, May 5, 2017 (Successor)		25,000,000			—			—
Issuance of Successor common stock		—			—			—
Balance, December 31, 2017 (Successor)		25,000,000			—			—

(1) Restricted common units are generally net-settled by our Predecessor unitholders to cover the required withholding tax upon vesting. The Predecessor unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were less than approximately $0.1 million for the period from January 1, 2017 through May 4, 2017 and were $0.6 million and $1.3 million for the years ended December 31, 2016 and 2015, respectively. These net-settlements had the effect of unit repurchases by the Company as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company.

Warrants

On the Effective Date, the Company entered into a warrant agreement with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Company issued Warrants to purchase up to 2,173,913 shares of the Company’s common stock (representing 8% of the Company’s outstanding common stock as of the Effective Date including shares of the Company’s common stock issuable upon full exercise of the Warrants, but excluding any common stock issuable under the MIP), exercisable for a five year period commencing on the Effective Date at an exercise price of $42.60 per share.

F-30

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The fair values for the warrants upon issuance on the Effective Date have been estimated using the Black-Scholes option pricing model using the following assumptions:

	Warrants Issued in
	Successor Period
Risk-free interest rate		2.06	%
Dividend yield		—
Expected life (in years)		5.0
Expected volatility		50.0	%
Strike Price	$	42.60
Calculated fair value	$	2.20

Predecessor’s General Partner Interest and IDRs.

On April 27, 2016, we acquired MEMP GP from Memorial Resource for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the IDRs in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the MEMP GP Acquisition, our Predecessor’s partnership agreement was amended and restated to convert the 0.1% general partner interest in the Predecessor held by MEMP GP into a non-economic general partner interest. Prior to June 1, 2016, Memorial Resource owned 100% of our Predecessor’s general partner, which owned 50% of our incentive distribution rights. The Funds collectively indirectly owned 50% of our incentive distribution rights.

Predecessor Common Units.

The common units were a separate class of the limited partner interest in our Predecessor and had limited voting rights as set forth in our Predecessor’s partnership agreement. The holders of units were entitled to participate in partnership distributions as discussed further below under “Predecessor’s Cash Distribution Policy” and exercise the rights or privileges available to limited partners under our Predecessor’s partnership agreement.

On February 13, 2015, all of the 5,360,912 outstanding subordinated units owned by MRD Holdco were converted into common units. The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP’s fourth quarter 2014 distribution. MRD Holdco sold all of the common units during the three months ended June 30, 2015.

2015 Purchase of Noncontrolling Interest

In connection with the 2015 Beta Acquisition, we purchased the noncontrolling interests in SPBPC. See Note 5 for further information.

Predecessor “At-the-Market” Equity Program

On May 25, 2016, the Predecessor entered into an equity distribution agreement for the sale of up to $60.0 million of common units under an at-the-market program (the “ATM Program”). Sales of common units were made under the ATM Program by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Market at market prices, or as otherwise agreed between the Predecessor and a sales agent.

During the year ended December 31, 2016, the Predecessor sold 1,178,102 common units under the ATM program. The sale of the units generated proceeds of approximately $1.8 million for the year ended December 31, 2016, which was net of approximately $0.5 million in fees. The Predecessor used the net proceeds from the sale of common units to repurchase senior notes.

2015 Predecessor Repurchases of Common Units

In December 2014, the board of directors of our Predecessor’s general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). Under the MEMP Repurchase Program, units could be repurchased and retired from time to time at our discretion on the open market. The MEMP Repurchase Program did not obligate us to repurchase any dollar amount or specific number of common units and could have been discontinued at any time. During the year ended December 31, 2015, our Predecessor repurchased $52.8 million in common units, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program. The MEMP Repurchase Program expired in December 2015.

F-31

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Allocations of Net Income (Loss)

Prior to the MEMP GP Acquisition, net income (loss) attributable to the Predecessor was allocated between our Predecessor’s general partner and the common unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our Predecessor’s general partner and the Funds. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control in a manner similar to the pooling of interest method prior to their acquisition date is allocated to the previous owners since they were affiliates of our Predecessor’s general partner. Subsequent to the MEMP GP Acquisition, net income (loss) attributable to the Predecessor is allocated entirely to the common unit holders.

Predecessor’s Cash Distribution Policy

In October 2016, the board of directors of our Predecessor’s general partner suspended distributions on common units primarily due to the current and expected commodity price environment and market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our Predecessor’s revolving credit facility. Additionally, under our Predecessor’s revolving credit facility, we could not pay distributions to unitholders in any such quarter in the event there existed a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we were not in pro forma compliance with our Predecessor’s revolving credit facility after giving effect to such distribution.

Minimum Quarterly Distribution. During the subordination period, the common units had the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus could be made on the subordinated units. These units were deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units were not entitled to receive any distributions from operating surplus until the common units had received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages were paid on the subordinated units. The practical effect of the subordinated units was to increase the likelihood that during the subordination period there would be available cash from operating surplus to be distributed on the common units. The subordination period ended on February 13, 2015.

Cash Distributions to Predecessor Unitholders

The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts):

								Distribution
				Amount		Aggregate		Received by
Quarter	Declaration Date	Record Date	Payment Date	Per Unit		Distribution		Affiliates
2nd Quarter 2016	July 26, 2016	August 5, 2016	August 12, 2016	$	0.0300	$	2.5	$	< 0.1
1st Quarter 2016	April 26, 2016	May 6, 2016	May 13, 2016	$	0.0300	$	2.5	$	< 0.1
4th Quarter 2015	January 26, 2016	February 5, 2016	February 12, 2016	$	0.1000	$	8.3	$	< 0.1
3rd Quarter 2015	October 26, 2015	November 5, 2015	November 12, 2015	$	0.3000	$	24.9	$	< 0.1
2nd Quarter 2015	July 24, 2015	August 5, 2015	August 12, 2015	$	0.5500	$	45.7	$	0.1
1st Quarter 2015	April 24, 2015	May 6, 2015	May 13, 2015	$	0.5500	$	46.3	$	0.2
4th Quarter 2014	January 26, 2015	February 5, 2015	February 12, 2015	$	0.5500	$	46.3	$	3.1

Previous Owners Capital

The following table summarizes our previous owners’ equity transactions related to the Property Swap with respect to the period indicated (dollars in thousands):

	Previous Owners
Balance, December 31, 2014 (Predecessor)	$	220,657
Net income (loss)		(2,268	)
Contributions		1,912
Net book value of net assets exchanged		(248,321	)
Deferred tax liability retained by previous owner		28,020
Balance, December 31, 2015 (Predecessor)	$	—

F-32

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 12. Earnings per Share/Unit

The following sets forth the calculation of earnings (loss) per share/unit, or EPS/EPU, for the periods indicated (in thousands, except per unit amounts):

	Successor		Predecessor
	Period from
	May 5, 2017		Period from
	through		January 1,			For the Year Ended
	December 31,		2017 through			December 31,
	2017		May 4, 2017			2016			2015
Net income (loss) attributable to Successor/Predecessor	$	1,286	$	(90,955	)	$	(540,398	)	$	(395,877	)
Less: Previous owners interest in net income (loss)		—		—			—			(2,268	)
Less: Predecessor's general partner's 0.1% interest in net income (loss) (1)		—		—			(168	)		(412	)
Less: Predecessor's IDRs attributable to corresponding period		—		—			—			112
Less: Net income (loss) allocated to participating restricted stockholders		35		—			—			—
Basic and diluted earnings available to common stockholders/limited partners	$	1,251	$	(90,955	)	$	(540,230	)	$	(393,309	)
Common shares/units:
Common shares/units outstanding — basic		25,000		83,807			83,351			82,897
Subordinated units		—		—			—			631
Dilutive effect of potential common shares		—		—			—			—
Common shares/units outstanding — diluted (2)		25,000		83,807			83,351			83,528
Net earnings per share/unit:
Basic	$	0.05	$	(1.09	)	$	(6.48	)	$	(4.71	)
Diluted	$	0.05	$	(1.09	)	$	(6.48	)	$	(4.71	)
Antidilutive stock options (3)		517		—			—			—
Antidilutive warrants (4)		2,174		—			—			—

(1) As a result of repurchases under the MEMP Repurchase Program, our Predecessor’s general partner had an approximate average 0.105% interest in us prior to the MEMP GP Acquisition for the five months ended May 31, 2016 and an approximate average of 0.105% interest in us for the year ended December 31, 2015.

(2) For the year ended December 31, 2016, 3,325,318 incremental phantom units under the treasury stock method were excluded from the calculation of diluted earnings per unit, due to their antidilutive effect as we were in a loss position.

(3) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

(4) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

Note 13. Equity-based Awards

On the Effective Date in connection with the Plan, the Company implemented the MIP for selected employees of the Company or its subsidiaries. An aggregate of 2,322,404 shares of the Company’s common stock are reserved for issuance under the MIP. MIP awards are granted in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance awards, stock awards and other incentive awards. To the extent that an award under the MIP is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the MIP. The MIP is administered by the board of directors of the Company.

On May 4, 2017, the board of directors approved grants of restricted stock unit awards and restricted stock options (collectively the “Emergence Awards”) to certain of the Company’s employees, including the Company’s executive officers. Emergence Awards will generally vest annually in three equal installments on each of the first three anniversaries of the Effective Date, subject to the grantee’s continued employment through each such vesting date. However, upon a grantee’s termination of employment by the Company without Cause, or due to death or Disability, or the grantee resigns from Service for Good Reason (as such terms are defined in the respective Emergence Award agreement), all unvested restricted stock unit awards shall fully vest upon such termination or resignation date.  Moreover, (i) upon a grantee’s termination of employment by the Company without Cause, or due to death or Disability, or the grantee resigns from Service for Good Reason (as such terms are defined in the respective Emergence Award agreement), any portion of the then unvested restricted stock options that would have vested had the grantee continued his or her Service during the 12 months following such termination or resignation shall vest on such termination or resignation date and (ii) upon a grantee’s termination of employment by the Company without Cause or the grantee resigns from Service for Good Reason, in each case, following a Change of Control, all unvested restricted stock options shall fully vest as of such termination or resignation date.  Notwithstanding the foregoing, the vesting of such Emergence Awards may be subject to and limited by employment-related agreements by and between the Company and grantee.

F-33

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Restricted Stock Units

The restricted stock units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock unit awards was $7.3 million at December 31, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.39 years.

The following table summarizes information regarding the restricted stock unit awards granted under the MIP for the period presented:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted stock units outstanding at May 5, 2017 (Successor)		614,754		$	13.77
Granted (2)		173,070		$	12.87
Forfeited		(105,032	)	$	13.77
Vested		—		$	—
Restricted stock units outstanding at December 31, 2017 (Successor)		682,792		$	13.54

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

(2) The aggregate grant date fair value of restricted stock units issued for the period from May 5, 2017 through December 31, 2017 was $2.2 million based on a grant date market price ranging from $10.00 to $13.77 per share.

Restricted Stock Options

The fair value for restricted stock options granted during the three months ended June 30, 2017 have been estimated using the Black-Scholes option pricing model using the following assumptions:

	Awards Issued in
	Successor Period
Risk-free interest rate		2.06	%
Dividend yield		—
Expected life (in years)		6.0
Expected volatility		50.0	%
Strike Price	$	21.58
Calculated fair value per stock option	$	5.01

No restricted stock options were granted after June 30, 2017.

The restricted stock options granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock option awards was $2.0 million at December 31, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.34 years.

The following table summarizes information regarding the restricted stock option awards granted under the MIP for the period presented:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Options			per Option (1)
Restricted stock options outstanding at May 5, 2017 (Successor)		614,754		$	5.01
Granted		1,876		$	5.01
Forfeited		(99,232	)	$	5.01
Vested		—		$	—
Restricted stock options outstanding at December 31, 2017 (Successor)		517,398		$	5.01

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

F-34

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

2017 Non-Employee Directors Compensation Plan

In June 2017, in connection with the Plan, the Company implemented the 2017 Non-Employee Directors Compensation Plan (“Directors Compensation Plan”) to attract and retain services of experienced non-employee directors of the Company or its subsidiaries. An aggregate of 200,000 shares of the Company’s common stock are reserved for issuance under the Directors Compensation Plan. Directors Compensation Plan awards are granted in the form of nonqualified stock options, restricted stock awards, restricted stock units, and other cash-based awards and stock-based awards. To the extent that an award under the Director Compensation Plan is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the Director Compensation Plan. Awards granted will generally vest annually in three equal installments on each of the first three anniversaries of the grant date, subject to the grantee’s continued employment through each such vesting date.

The restricted stock units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock unit awards was $0.2 million at December 31, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.45 years.

The following table summarizes information regarding the restricted stock awards granted under the Director Compensation Plan for the period presented:

			Weighted-
			Average Grant
	Number of		Date Fair Value
	Units		per Unit (1)
Restricted stock units outstanding at May 5, 2017 (Successor)		—	$	—
Granted (2)		16,341	$	13.77
Forfeited		—	$	—
Vested		—	$	—
Restricted stock units outstanding at December 31, 2017 (Successor)		16,341	$	13.77

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

(2) The aggregate grant date fair value of restricted stock option awards issued in 2017 was $0.2 million based on grant date market price of $13.77 per share.

Predecessor Restricted Common Units

In December 2011, the board of directors of our Predecessor’s general partner adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for employees, officers, consultants and directors of the general partner and any of its affiliates, who perform services for the Predecessor. The LTIP authorized the grant of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights (“DERs”), other unit-based awards and unit awards. The LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP was administered by the board of directors of our Predecessor’s general partner or a committee thereof. During the years ended December 31, 2016 and 2015 there was multiple awards of restricted common units that were granted under the LTIP to executive officers and independent directors of our Predecessor’s general partner and other Memorial Resource employees.

The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and typically graded vesting provisions in which one-third of each award vested on the first, second, and third anniversaries of the date of grant. Award recipients had all the rights of a Predecessor unitholder in the partnership with respect to the restricted common units, including the right to receive distributions thereon if and when distributions were made by the Predecessor to its unitholders. The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expired.

Based on the market price per unit on the date of grant, the aggregate fair value of the restricted common units awarded to our Predecessor’s general partner’s executive officers and other employees during the years ended December 31, 2016 and 2015 was $0.1 million and $12.3 million, respectively. The restricted common units granted were accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. The fair value of the restricted unit awards granted to the independent directors of our Predecessor’s general partner were also recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs are recorded as direct general and administrative expenses.

On May 1, 2017, the Company effectively cancelled the unvested restricted common unit awards under the LTIP and recorded $2.3 million in compensation expense.

F-35

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The following table summarizes information regarding restricted common unit awards for the periods presented:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted common units outstanding at December 31, 2014 (Predecessor)		1,093,520		$	20.93
Granted (2)		827,704		$	14.90
Forfeited		(69,059	)	$	18.35
Vested		(483,627	)	$	20.37
Restricted common units outstanding at December 31, 2015 (Predecessor)		1,368,538		$	17.61
Granted (3)		50,000		$	2.41
Forfeited		(27,537	)	$	16.99
Vested		(958,841	)	$	18.01
Restricted common units outstanding at December 31, 2016 (Predecessor)		432,160		$	15.00
Granted		—		$	—
Forfeited		(12,952	)	$	9.51
Vested		(43,045	)	$	10.40
Cancelled		(376,163	)	$	15.72
Restricted common units outstanding at May 4, 2017 (Predecessor)		—		$	—

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

(2) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on grant date market prices ranging from of $6.20 to $15.45 per unit.

(3) The aggregate grant date fair value of restricted common unit awards issued in 2016 was $0.1 million based on grant date market price of $2.41 per unit.

On June 1, 2016, in connection with the MEMP GP Acquisition, as discussed in Note 1, the board of directors of our Predecessor’s general partner approved the acceleration of the vesting schedule of unvested awards under the LTIP for the employees that remained with Memorial Resource. The grant-date fair value compensation cost of approximately $0.1 million was reversed and the modified-date grant fair value compensation cost of $0.5 million was recognized.

On March 9, 2016, certain employees were impacted by an involuntary termination which, upon the approval of the board of directors of our Predecessor’s general partner, accelerated the vesting schedule of unvested awards under the LTIP that otherwise would have been forfeited upon an involuntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of approximately $0.3 million was recognized.

Predecessor Phantom Units

The following table summarizes information regarding the Predecessor’s phantom unit awards granted under the LTIP:

	Number of
	Units
Phantom units outstanding at December 31, 2015 (Predecessor)		—
Granted		6,169,018
Forfeited		(188,325	)
Phantom units outstanding at December 31, 2016 (Predecessor)		5,980,693
Granted		—
Forfeited		(132,347	)
Vested		(155,601	)
Phantom units outstanding at May 4, 2017 (Predecessor)		5,692,745
Cancelled		(5,692,745	)
Phantom units outstanding at December 31, 2017 (Successor)		—

F-36

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Phantom units issued to non-employee directors of our Predecessor in January 2016 vested on the first anniversary of the date of grant and were settled in cash for less than $0.1 million. Phantom units issued to certain employees in June 2016 were scheduled to vest in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant. The awards included distribution equivalent rights (“DERs”) pursuant to which the recipient would receive, upon vesting, receive a cash payment with respect to each phantom unit equal to any cash distributions that we pay to a holder of a common unit. DERs are treated as additional compensation expense. Upon vesting, the phantom units were scheduled to be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our Predecessor’s general partner, in its discretion, was permitted to elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. Upon emergence from bankruptcy, the remaining awards were settled in cash for less than $0.1 million.

Compensation Expense

The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):

	Successor		Predecessor
	Period from		Period from
	May 5, 2017		January 1, 2017			For the Year Ended
	through		through			December 31,
	December 31, 2017		May 4, 2017			2016		2015
Equity classified awards
Restricted stock units (Successor)	$	1,947	$	—		$	—	$	—
Restricted stock options (Successor)		569		—			—		—
Restricted common units (Predecessor)		—		3,713			7,206		10,809
Liability classified awards
Phantom units (Predecessor)		—		(46	)		322		—
	$	2,516	$	3,667		$	7,528	$	10,809

Note 14. Related Party Transactions

On June 1, 2016, Memorial Resource and certain affiliates of NGP became unaffiliated entities after we closed the MEMP GP Acquisition, as discussed in Note 1.

NGP Affiliated Companies

During the year ended December 31, 2016, we paid less than $0.1 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

Common Control Acquisitions

2016 Acquisition

On June 1, 2016, as discussed in Note 1, the Predecessor acquired all of the equity interests in our Predecessor’s general partner, MEMP GP, from Memorial Resource for cash consideration of approximately $0.8 million. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the closing of the transaction, our Predecessor’s partnership agreement was amended and restated to, among other things, (i) convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of our Predecessor had the ability to elect the members of MEMP GP’s board of directors. On June 1, 2016, the Predecessor also acquired the remaining 50% of the IDRs of MEMP owned by an NGP affiliate.

F-37

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

2015 Acquisition

On February 23, 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78.4 million in cash for Memorial Resource’s East Texas and Louisiana oil and gas properties. The properties MEMP received are primarily located in the Joaquin Field in Shelby and Panola counties in East Texas. This acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisition as if the Predecessor owned the assets for the period after common control commenced through the acquisition date. The Predecessor recorded the following net assets (in thousands):

Accounts receivable	$	2,372
Other receivables		5,478
Prepaid expenses and other current assets		1,874
Property and equipment, net		263,210
Accounts payable		(3,586	)
Accounts payable - affiliate		(1,290	)
Revenues payable		(1,110	)
Accrued liabilities		(11,347	)
Asset retirement obligations		(4,559	)
Net assets	$	251,042

2015 Divestiture

On November 2, 2015, in connection with an auction process administered by a third-party, we divested certain oil and natural gas properties in the Permian Basin with a net value of approximately $0.2 million to an affiliate of NGP for a purchase price of approximately $0.9 million. Due to common control considerations, $0.7 million difference between the proceeds from the sale and the net book value of the properties was recognized in the equity statement as a contribution.

Related Party Agreements

The Predecessor and certain of our former affiliates entered into various documents and agreements. These agreements were negotiated among affiliated parties and, consequently, were not the result of arm’s-length negotiations.Since our emergence from bankruptcy on May 4, 2017, there have been no transactions in excess of $120,000 between us and a related person in which the related person had a direct or indirect material interest.  

Predecessor Omnibus Agreement

Memorial Resource provided management, administrative and operating services to the Predecessor and our Predecessor’s general partner pursuant to our Predecessor’s Omnibus Agreement. Upon completion of the MEMP GP Acquisition, the Predecessor’s Omnibus Agreement was terminated and the Predecessor entered into a transition services agreement with Memorial Resource. The following table summarizes the amount of general and administrative expenses recognized under the Predecessor’s Omnibus Agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):

Successor		Predecessor
Period from		Period from
May 5, 2017		January 1, 2017		For the Year Ended
through		through		December 31,
December 31, 2017		May 4, 2017		2016		2015
$	—	$	—	$	11,867	$	32,281

Transition Services Agreement

On June 1, 2016, we closed the MEMP GP Acquisition. Upon closing of the MEMP GP Acquisition, we and Memorial Resource became unaffiliated entities. We terminated our Predecessor’s Omnibus Agreement as noted above and entered into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities. The Company did not incur any costs under the transition services agreement for the period from May 5, 2017 through December 31, 2017 or for the period from January 1, 2017 through May 4, 2017. During the year ended December 31, 2016, we recorded $1.6 million of general and administrative expense related to the transition services agreement with Memorial Resource.

F-38

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Beta Management Agreement

In connection with the December 2012 Beta acquisition, Memorial Resource entered into a management agreement with its wholly owned subsidiary, Beta Operating Company, LLC (“Beta Operating”), pursuant to which Memorial Resource agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with our subsidiary, Rise Energy Beta, LLC, related to the Beta properties in exchange for an annual management fee. Pursuant to such management agreement and in connection with such operating agreements, Memorial Resource had the right to receive approximately $0.4 million from Rise Energy Beta, LLC annually. This agreement was terminated in November 2015 in connection with the 2015 Beta Acquisition.

On June 1, 2016, Memorial Resource assigned and transferred Beta Operating to the Predecessor in connection with the MEMP GP Acquisition.

Classic Agreements

In November 2011, Classic Hydrocarbons Operating, LLC, a subsidiary of Memorial Resource (“Classic Operating”), and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), a subsidiary of MRD Holdco, entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline’s Joaquin gathering system.

In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement had a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July 1, 2015, the fee was reduced to $0.40 per barrel. In February 2015, in connection with and as part of the Property Swap, Classic Hydrocarbons Holdings, L.P. sold all of the equity interests owned by it in Classic Operating as well as Craton Energy GP III, LLC (“Craton GP”) and Craton Energy Holdings III, LP (“Craton LP”), two subsidiaries of Memorial Resource, to OLLC, and Classic Operating, Craton GP and Craton LP were merged into OLLC. OLLC was therefore the successor to Classic Operating under the amended gas gathering agreement which was later terminated in November 2015 and water disposal agreement.

Classic Pipeline assigned its saltwater disposal system to OLLC in November 2015. Due to common control considerations, we recorded the receipt of this asset at historical cost and recognized a contribution of approximately $2.1 million in the equity statement. Prior to the assignment from Classic Pipeline, for the years ended December 31, 2015, the Predecessor incurred gathering and salt water disposal fees of approximately $3.2 million from Classic Pipeline, an affiliate.

Note 15. Commitments and Contingencies

Litigation & Environmental

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. On January 13, 2017, the Company received a letter from the Environmental Protection Agency (“EPA”) concerning potential violations of the Clean Air Act (“CAA”) section 112(r) associated with our Bairoil complex in Wyoming. The Company met with the EPA on February 16, 2017 to present relevant information related to the allegations. On September 12, 2017, the EPA filed an Administrative Compliance Order on Consent for which the Company must bring all outstanding issues to closure no later than June 30, 2018. We currently cannot estimate the potential penalties, fines or other expenditures, if any, that may result from any EPA actions relating to the alleged violations and, therefore, we cannot determine if the ultimate outcome of this matter will have a material impact on the Company’s financial position, results of operations or cash flows. Other than the Chapter 11 proceedings and the alleged CAA violations discussed herein, based on facts currently available, we are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.

F-39

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable.

The following table presents the activity of our environmental reserves for the periods presented:

	Successor		Predecessor
	2017		2016			2015
	(In thousands)		(In thousands)
Balance at beginning of period	$	—	$	216		$	2,092
Charged to costs and expenses		—		—			—
Payments		—		(216	)		(1,876	)
Balance at end of period	$	—	$	—		$	216

At December 31, 2017 and 2016, we had no environmental reserves recorded.

Third-Party Midstream Transaction

In October 2017, we recognized an approximately $17.0 million gain in connection with the sale of a third-party midstream entity with whom our natural gas gathering and processing agreements entitled us to a percentage of the proceeds in the event of a sale.

Sinking Fund Trust Agreement

Beta Operating Company, LLC (formerly REO) assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2017, the account balance included in restricted investments was approximately $4.1 million.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

Beta Operating Company, LLC has an obligation with the BOEM in connection with the 2009 acquisition of the Beta properties. The trust account has the required minimum balance of $152.0 million at December 31, 2017 and is fully cash funded.

In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. In 2015, the BOEM issued a preliminary report that indicated the estimated cost of decommissioning may further increase. The implementation of this increase is currently on hold and we do not expect resolution of a negotiated decommissioning estimate until 2018.

The gross held-to-maturity investments held in the trust account as of December 31, 2017 for the U.S. Bank money market cash equivalent was $152.3 million.

Operating Leases

We have leases for offshore Southern California pipeline right-of-way use as well as office space in our operating regions. We also lease equipment, compressors and incur surface rentals related to our business operations. The previous owners also leased equipment and office space under various operating leases and incurred surface rentals related to their operations.

For the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015, we recognized $6.3 million, $3.1 million, $10.9 million and $16.9 million of rent expense, respectively.

F-40

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):

			Payment or Settlement Due by Period
Operating leases	Total		2018		2019		2020		2021		2022		Thereafter
Operating leases	$	14,433	$	6,155	$	2,093	$	2,131	$	2,154	$	260	$	1,640

Purchase Commitments

At December 31, 2017, we had a CO₂ purchase commitment with a third party associated with our Wyoming Bairoil properties.The price we will pay for CO₂ generally varies depending on the amount of CO₂ delivered and the price of oil. The table below outlines our purchase commitments under these contracts based on pricing at December 31, 2017 (in thousands):

			Payment or Settlement Due by Period
Purchase commitment	Total		2018		2019		2020		2021		2022		Thereafter
CO2 minimum purchase commitment	$	13,633	$	4,801	$	4,659	$	4,173	$	—	$	—	$	—

Minimum Volume Commitment

At December 31, 2017, we had a long-term minimum volume commitment with a third party associated with a certain portion of our properties located in East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands):

			Payment or Settlement Due by Period
Minimum volume commitment	Total		2018		2019		2020		2021		2022		Thereafter
Midstream services	$	15,383	$	3,075	$	3,075	$	3,083	$	3,075	$	3,075	$	—

Note 16. Income Tax

Amplify Energy is a corporation and as a result, is subject to U.S. federal, state and local income taxes.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The provisions of the Tax Act that impact us include, but are not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) temporary bonus depreciation that will allow for full expensing of qualified property, and (4) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80% of taxable income. In conjunction with the Tax Act, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under Accounting Standards Codification 740 “Income Tax” (“ASC 740”). In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act.

In connection with our initial analysis of the impact of the Tax Act, we provisionally decreased our net deferred tax assets by $23.0 million for the reduction in the federal tax rate and correspondingly decreased the associated valuation allowance by $23.0 million. While we have not completed our accounting for the income tax effects of the Tax Act, there were no specific impacts of the Tax Act for which a reasonable estimate could not be made. Based on a continued analysis of the estimates, it is anticipated that additional revisions may occur during the allowable measurement period.  

F-41

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The components of income tax benefit (expense) are as follows:

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017		For the Year Ended
	through			through		December 31,
	December 31, 2017			May 4, 2017		2016			2015
	(In thousands)			(In thousands)
Current taxes:
Federal	$	4		$	—	$	6		$	(11	)
State		(34	)		17		8			(48	)
Total current income tax benefit (expense)		(30	)		17		14			(59	)
Deferred taxes:
Federal		1,933			71		8			1,193
State		273			3		(195	)		1,041
Total deferred income tax benefit (expense)		2,206			74		(187	)		2,234
Total income tax benefit (expense)	$	2,176		$	91	$	(173	)	$	2,175

The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows:

	Successor			Predecessor
	Period from			Period from
	May 5, 2017			January 1, 2017			For the Year Ended
	through			through			December 31,
	December 31, 2017			May 4, 2017			2016			2015
	(In thousands)			(In thousands)
Expected tax benefit (expense) at federal statutory rate	$	310		$	5,764		$	191,870		$	139,183
State income tax benefit (expense), net of federal benefit		240			30			382			645
Non-deductible expenses		(187	)		—			—			—
Changes in valuation allowances		24,767			—			—			—
Remeasurement of federal deferred tax assets due rate change		(22,958	)		—			—			—
Pass-through entities (1)		—			(5,686	)		(191,921	)		(137,704	)
Other		4			(17	)		(504	)		51
Total income tax benefit (expense)	$	2,176		$	91		$	(173	)	$	2,175

(1) MEMP, a publicly traded partnership with qualifying income, was a pass-through entity for federal income tax purposes.

F-42

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands):

	Successor			Predecessor
	December 31,			December 31,
	2017			2016
Deferred income tax assets:
Property, Plant & Equipment	$	19,423		$	—
Derivative instrument		6,251			—
Net operating loss carryforward		10,452			9
Asset retirement obligation		1,223			875
Other		779			33
Total deferred income tax assets:		38,128			917
Valuation allowance		(38,128	)		(865	)
Net deferred income tax assets		—			52
Deferred income tax liabilities:
Property, plant and equipment	$	—		$	1,522
Derivatives		—			770
Other		—			40
Total deferred income tax liabilities		—			2,332
Net deferred income tax liabilities	$	—		$	2,280

As of December 31, 2017, the Company had U.S. federal net operating loss carry forwards of approximately $46.8 million that will expire in years 2035 - 2037 and state net operating loss carry forwards of approximately $8.8 million which will expire in varying amounts beginning in 2035.

In assessing deferred tax assets, the Company considers whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, the Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies. As of December 31, 2017, a valuation allowance of $38.1 million had been recorded.

Uncertain Income Tax Position. We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. We had no unrecognized tax benefits as of December 31, 2017.

Tax Audits and Settlements. Generally, our income tax years 2014 through 2017 remain open and subject to examination by the Internal Revenue Service or state tax jurisdictions where we conduct operations. In certain jurisdictions we operate through more than one legal entity, each of which may have different open years subject to examination.

F-43

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 17. Quarterly Financial Information (Unaudited)

The following tables present selected quarterly financial data for the periods indicated. Earnings per share/unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per share/unit may not necessarily equal the total for the year.

	Predecessor						Successor
				Period from			Period from
				April 1, 2017			May 5, 2017
	First			through			through			Third			Fourth
	Quarter			May 4, 2017			June 30, 2017			Quarter			Quarter
	(In thousands, except per share/unit amounts)
Revenues	$	81,380		$	27,821		$	42,395		$	75,589		$	87,495
Operating income (loss)		(421	)		8,384			2,654			(6,043	)		2,573
Net income (loss)		(16,377	)		(74,578	)		(906	)		(7,536	)		9,728
Net income (loss) attributable to Successor/Predecessor		(16,377	)		(74,578	)		(906	)		(7,536	)		9,728
Net income (loss) available to common stockholders/limited partners		(16,377	)		(74,578	)		(906	)		(7,536	)		9,463
Basic and diluted earnings per unit/share		(0.20	)		(0.89	)		(0.04	)		(0.30	)		0.38

	Predecessor
	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except per unit amounts)
For the Year Ended December 31, 2016
Revenues	$	60,866		$	68,066		$	74,222		$	81,426
Operating income (loss)		(5,449	)		(156,971	)		(6,336	)		(267,783	)
Net income (loss)		(38,097	)		(147,550	)		(32,866	)		(321,885	)
Net income (loss) attributable to Memorial Production Partners LP		(38,097	)		(147,550	)		(32,866	)		(321,885	)
Limited partners’ interest in net income (loss)		(38,057	)		(147,422	)		(32,866	)		(321,885	)
Basic and diluted earnings per unit		(0.46	)		(1.78	)		(0.39	)		(3.85	)

See Notes 4 and 12 for additional information regarding earnings per share/unit.

Note 18. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.

	Successor			Predecessor
	December 31,			December 31,			December 31,
	2017			2016			2015
	(In thousands)			(In thousands)
Evaluated oil and natural gas properties	$	603,053		$	3,115,012		$	3,616,325
Support equipment and facilities		100,225			199,093			205,876
Accumulated depletion, depreciation, and amortization		(34,429	)		(1,743,274	)		(1,878,549	)
Total	$	668,849		$	1,570,831		$	1,943,652

F-44

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:

	Successor		Predecessor
	Period from
	May 5, 2017		Period from
	through		January 1,		For the Year Ended
	December 31,		2017 through		December 31,
	2017		May 4, 2017		2016		2015
	(In thousands)		(In thousands)
Property acquisition costs, proved	$	—	$	—	$	—	$	77,834
Property acquisition costs, unproved		—		—		—		1,887
Exploration		—		—		792		2,078
Development		51,925		9,573		54,310		233,241
Total	$	51,925	$	9,573	$	55,102	$	315,040

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that 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.

We engaged Ryder Scott to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2017. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

F-45

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:

	2017		2016		2015
Oil ($/Bbl):
WTI (1)	$	51.34	$	42.75	$	46.79
NGL ($/Bbl):
WTI (1)	$	51.34	$	42.75	$	46.79
Natural Gas ($/MMbtu):
Henry Hub (2)	$	2.98	$	2.48	$	2.58

(1) The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.

(2) The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

The following tables set forth estimates of the net reserves for the periods indicated:

	For the period from May 5, 2017 through December 31, 2017 (Successor)
	Oil			Gas			NGLs			Equivalent
	(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
Beginning of period		80,960			419,472			30,572			1,088,660
Extensions and discoveries		121			4,900			261			7,195
Production		(2,380	)		(21,885	)		(1,114	)		(42,850	)
Revision of previous estimates		(6,697	)		4,071			(4,530	)		(63,284	)
End of year		72,004			406,558			25,189			989,721
Proved developed reserves:
Beginning of period		57,803			297,101			21,963			775,693
End of year		50,014			299,481			17,982			707,459
Proved undeveloped reserves:
Beginning of period		23,157			122,371			8,609			312,967
End of year		21,990			107,077			7,207			282,262

	For the period from January 1, 2017 through May 4, 2017 (Predecessor)
	Oil			Gas			NGLs			Equivalent
	(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		65,741			371,016			25,184			916,565
Extensions and discoveries		53			45			8			410
Production		(1,204	)		(12,411	)		(616	)		(23,336	)
Revision of previous estimates		16,370			60,822			5,996			195,021
End of period		80,960			419,472			30,572			1,088,660
Proved developed reserves:
Beginning of year		45,536			280,035			18,923			666,786
End of period		57,803			297,101			21,963			775,693
Proved undeveloped reserves:
Beginning of year		20,205			90,981			6,261			249,779
End of period		23,157			122,371			8,609			312,967

F-46

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Year Ended December 31, 2016 (Predecessor)
	Oil			Gas			NGLs			Equivalent
	(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		90,945			461,526			43,395			1,267,571
Extensions and discoveries		297			288			42			2,320
Production		(3,883	)		(44,776	)		(2,283	)		(81,773	)
Sale of minerals in place		(3,228	)		(15,227	)		(123	)		(35,328	)
Revision of previous estimates		(18,390	)		(30,795	)		(15,847	)		(236,225	)
End of year		65,741			371,016			25,184			916,565
Proved developed reserves:
Beginning of year		50,817			311,147			30,315			797,936
End of year		45,536			280,035			18,923			666,786
Proved undeveloped reserves:
Beginning of year		40,128			150,379			13,080			469,635
End of year		20,205			90,981			6,261			249,779

	Year Ended December 31, 2015 (Predecessor)
	Oil			Gas			NGLs			Equivalent
	(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		100,258			727,216			59,034			1,682,960
Extensions and discoveries		2,319			8,686			558			25,950
Purchase of minerals in place		10,132			34,128			367			97,122
Production		(4,087	)		(50,875	)		(2,820	)		(92,315	)
Sale of minerals in place		(380	)		(13,731	)		(758	)		(20,559	)
Revision of previous estimates		(17,297	)		(243,898	)		(12,986	)		(425,587	)
End of year		90,945			461,526			43,395			1,267,571
Proved developed reserves:
Beginning of year		54,723			417,247			37,260			969,141
End of year		50,817			311,147			30,315			797,936
Proved undeveloped reserves:
Beginning of year		45,535			309,969			21,774			713,819
End of year		40,128			150,379			13,080			469,635

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

• The 98.9 Bcfe reduction in reserves for the period from May 5, 2017 through December 31, 2017 is primarily due to a 13.4 Bcfe upward pricing revision and a 76.7 Bcfe downward revision due to updated well performance data and future anticipated development and maintenance cost increases. We added 7.2 Bcfe during the period from May 5, 2017 through December 31, 2017 due to extensions and discoveries.

• The 172.1 Bcfe increase in reserves for the January 1, 2017 through May 4, 2017 is primarily due to a 204.6 Bcfe upward pricing revision and a 9.6 Bcfe downward revision due to updated well performance data. Proved undeveloped reserves increased primarily due to upward pricing during the period from January 1, 2017 through May 4, 2017.

• The 351.0 Bcfe reduction in reserves for the year ended December 31, 2016 is primarily due to a 148.3 Bcfe downward pricing revision and an 87.9 Bcfe downward revision due to updated well performance data. We divested 35.3 Bcfe during the year ended December 31, 2016. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2016.

• The 415.4 Bcfe reduction in reserves for the year ended December 31, 2015 is primarily due to a 413 Bcfe downward pricing revision and a 13 Bcfe downward revision due to updated well performance data. We acquired 97.1 Bcfe during the year ended December 31, 2015, the largest being the 2015 Beta Acquisition of 58.5 Bcfe. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2015.

F-47

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

See Note 5 for additional information on acquisitions and divestitures.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

The standardized measure of discounted future net cash flows is as follows:

	Successor			Predecessor
	Period from
	May 5, 2017			Period from
	through			January 1,			For the Year Ended
	December 31,			2017 through			December 31,
	2017			May 4, 2017			2016			2015
	(In thousands)			(In thousands)
Future cash inflows	$	5,149,623		$	5,246,487		$	3,666,731		$	5,952,935
Future production costs		(2,982,035	)		(3,275,952	)		(2,384,195	)		(3,194,577	)
Future development costs		(530,133	)		(492,610	)		(440,496	)		(808,512	)
Future income tax expense		—			—			—			—
Future net cash flows for estimated timing of cash flows		1,637,455			1,477,925			842,040			1,949,846
10% annual discount for estimated timing of cash flows		(869,784	)		(786,836	)		(446,199	)		(1,360,292	)
Standardized measure of discounted future net cash flows	$	767,671		$	691,089		$	395,841		$	589,554

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2017:

	Successor			Predecessor
	Period from
	May 5, 2017			Period from
	through			January 1,			For the Year Ended
	December 31,			2017 through			December 31,
	2017			May 4, 2017			2016			2015
	(In thousands)			(In thousands)
Beginning of year	$	691,089		$	395,841		$	589,554		$	2,911,987
Sale of oil and natural gas produced, net of production costs		(100,946	)		(57,420	)		(107,357	)		(128,382	)
Purchase of minerals in place		—			—			—			75,998
Sale of minerals in place		—			—			(28,277	)		(45,100	)
Extensions and discoveries		7,187			1,320			2,016			18,582
Changes in income taxes, net		—			—			—			63,180
Changes in prices and costs		161,106			306,375			(404,870	)		(2,764,481	)
Previously estimated development costs incurred		61,851			9,227			89,748			322,446
Net changes in future development costs		(31,438	)		(55,333	)		254,043			448,089
Revisions of previous quantities		(27,060	)		99,591			14,414			(344,775	)
Accretion of discount		46,072			13,195			58,956			297,517
Change in production rates and other		(40,190	)		(21,707	)		(72,386	)		(265,507	)
End of year	$	767,671		$	691,089		$	395,841		$	589,554

F-48

AMPLIFY ENERGY CORP.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note. 19 Subsequent Events

Reduction in Force

On February 6, 2018, certain employees were impacted by a workforce reduction resulting in an involuntary termination of 19 employees across the Company.

Departure of Certain Directors or Certain Officers

On January 9, 2018, Alex Shayevsky resigned from our board of directors. Mr. Shayevsky served on our audit committee and compensation committee. There were no disagreements between Mr. Shayevsky and us which led to Mr. Shayevsky’s resignation from the board.

F-49