Amplify Energy (AMPYW) 10-Q 2018 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–Q

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

For the quarterly period ended March 31, 2018

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

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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ☐	Accelerated filer  ☑
Non-accelerated filer  ☐  (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  ☑

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 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 May 4, 2018, the registrant had 25,053,758 outstanding shares of common stock, $0.0001 par value outstanding.

AMPLIFY ENERGY CORP.

Table of Contents

		Page
	Glossary of Oil and Natural Gas Terms	1
	Names of Entities	3
	Cautionary Note Regarding Forward-Looking Statements	4
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2018 (Successor Period) and December 31, 2017 (Successor Period)	7
	Unaudited Condensed Statements of Consolidated Operations for the Three Months Ended March 31, 2018 (Successor Period) and the Three Months Ended March 31, 2017 (Predecessor Period)	8
	Unaudited Condensed Statements of Consolidated Cash Flows for the Three Months Ended March 31, 2018 (Successor Period) and the Three Months Ended March 31, 2017 (Predecessor Period)	9
	Unaudited Condensed Statements of Consolidated Equity for the Three Months Ended March 31, 2018 (Successor Period) and for the Three Months Ended March 31, 2017 (Predecessor Period)	10
	Notes to Unaudited Condensed Consolidated Financial Statements
	Note 1 – Organization and Basis of Presentation	11
	Note 2 – Summary of Significant Accounting Policies	12
	Note 3 – Revenue	14
	Note 4 – Acquisitions and Divestitures	15
	Note 5 – Fair Value Measurements of Financial Instruments	16
	Note 6 – Risk Management and Derivative Instruments	17
	Note 7 – Asset Retirement Obligations	19
	Note 8 – Long-term Debt	20
	Note 9 – Equity (Deficit)	20
	Note 10 – Earnings per Share/Unit	21
	Note 11 – Long-Term Incentive Plans	21
	Note 12 – Related Party Transactions	23
	Note 13 – Commitments and Contingencies	23
	Note 14 – Income Taxes	24
	Note 15 – Subsequent Events	24
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	34
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	35
Item 6.	Exhibits	35
Signatures		37

i

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.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcfe: One billion cubic feet of natural gas equivalent.

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.

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.

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.

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.

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 a working interest.

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.  

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million Btu.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

MMcfe/d: One MMcfe per day.

Net Production: Production that is owned by us less royalties and production due to others.

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 occurrence.

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

1

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.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

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.

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.

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 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.

2

NAMES OF ENTITIES

As used in this Form 10-Q, 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; and

• “OLLC” refers to Amplify Energy Operating LLC, our wholly owned subsidiary through which we operate our properties.

3

CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and section 21E of the Securities Exchange Act of 1934, as amended, 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.

4

All statements, other than statements of historical fact included in this report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “would,” “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 secured reserve-based revolving credit facility;

• the effect of changes in our senior management;

• 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; and

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

5

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 “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2017 filed with the SEC on March 12, 2018 (“2017 Form 10-K”) and “Part II—Item 1A. Risk Factors” appearing within this report 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.

6

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares/units)

	Successor			Successor
	March 31,			December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	5,717		$	6,392
Restricted cash		325			—
Accounts receivable		31,516			36,391
Short-term derivative instruments		15,662			28,546
Prepaid expenses and other current assets		6,349			7,220
Assets held for sale (see Note 4)		2,036			—
Total current assets		61,605			78,549
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		565,328			603,053
Support equipment and facilities		100,528			100,225
Other		6,133			6,133
Accumulated depreciation, depletion and impairment		(46,186	)		(35,979	)
Property and equipment, net		625,803			673,432
Long-term derivative instruments		156			—
Restricted investments		157,124			156,938
Assets held for sale (see Note 4)		33,933			—
Other long-term assets		7,839			8,545
Total assets	$	886,460		$	917,464
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,635		$	1,941
Revenues payable		23,381			22,427
Accrued liabilities (see Note 2)		17,304			18,233
Short-term derivative instruments		2,673			—
Assets held for sale (see Note 4)		1,102			—
Total current liabilities		48,095			42,601
Long-term debt (see Note 8)		347,000			376,000
Asset retirement obligations		72,415			99,460
Long-term derivative instruments		5,401			5,470
Assets held for sale (see Note 4)		15,409			—
Total liabilities		488,320			523,531
Commitments and contingencies (see Note 13)
Stockholders'/ partners' equity:
Preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at March 31, 2018 and December 31, 2017, respectively		—			—
Warrants, 2,173,913 warrants issued and outstanding at March 31, 2018 and December 31, 2017		4,788			4,788
Common stock, $0.0001 par value: 300,000,000 shares authorized; 25,000,000 shares issued and outstanding at March 31, 2018 and December 31, 2017		3			3
Additional paid-in capital		388,824			387,856
Accumulated earnings (deficit)		4,525			1,286
Total stockholders'/partners' equity		398,140			393,933
Total liabilities and equity	$	886,460		$	917,464

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

7

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(In thousands, except per shares/unit amounts)

	Successor			Predecessor
	For the Three			For the Three
	Months Ended			Months Ended
	March 31, 2018			March 31, 2017
Revenues:
Oil and natural gas sales	$	87,847		$	81,284
Other revenues		85			96
Total revenues		87,932			81,380
Costs and expenses:
Lease operating expense		29,570			25,986
Gathering, processing and transportation		5,600			8,035
Exploration		34			16
Taxes other than income		5,037			4,266
Depreciation, depletion and amortization		12,958			27,882
General and administrative expense		10,657			23,370
Accretion of asset retirement obligations		1,718			2,495
(Gain) loss on commodity derivative instruments		10,456			(10,241	)
(Gain) loss on sale of properties		2,373			—
Other, net		—			(8	)
Total costs and expenses		78,403			81,801
Operating income (loss)		9,529			(421	)
Other income (expense):
Interest expense, net		(5,772	)		(8,400	)
Other income (expense)		—			6
Total other income (expense)		(5,772	)		(8,394	)
Income (loss) before reorganization items, net and income taxes		3,757			(8,815	)
Reorganization items, net		(518	)		(7,653	)
Income tax benefit (expense)		—			91
Net income (loss)		3,239			(16,377	)
Net income (loss) attributable to common stockholders/limited partners	$	3,239		$	(16,377	)
Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor	$	3,239		$	(16,377	)
Net (income) allocated to participating restricted stockholders		(83	)		—
Net income (loss) available to common stockholders/limited partners	$	3,156		$	(16,377	)
Earnings per share/unit: (See Note 10)
Basic and diluted earnings per share/unit	$	0.13		$	(0.20	)
Weighted average common shares/units outstanding:
Basic and diluted		25,000			83,810

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

8

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(In thousands)

	Successor			Predecessor
	For the Three			For the Three
	Months Ended			Months Ended
	March 31, 2018			March 31, 2017
Cash flows from operating activities:
Net income (loss)	$	3,239		$	(16,377	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		12,958			27,882
(Gain) loss on derivative instruments		10,456			(10,241	)
Cash settlements (paid) received on expired derivative instruments		4,876			10,826
Cash settlements (paid) on terminated derivatives		—			94,146
Deferred income tax expense (benefit)		—			(74	)
Amortization of deferred financing costs		541			—
Accretion of asset retirement obligations		1,718			2,495
(Gain) loss on sale of properties		2,373			—
Share/unit-based compensation (see Note 11)		1,176			1,125
Settlement of asset retirement obligations		—			(113	)
Reorganization items, net		—			3,767
Other		—			41
Changes in operating assets and liabilities:
Accounts receivable		2,839			3,761
Prepaid expenses and other assets		(115	)		4,099
Payables and accrued liabilities		2,086			4,650
Other		—			(222	)
Net cash provided by operating activities		42,147			125,765
Cash flows from investing activities:
Additions to oil and gas properties		(13,098	)		(3,908	)
Additions to other property and equipment		—			(50	)
Additions to restricted investments		(186	)		(154	)
Other		—			(150	)
Net cash (used in) investing activities		(13,284	)		(4,262	)
Cash flows from financing activities:
Advances on revolving credit facilities		5,000			16,600
Payments on revolving credit facilities		(34,000	)		(73,453	)
Restricted units returned to plan		—			(1	)
Other		(213	)		—
Net cash (used in) provided by financing activities		(29,213	)		(56,854	)
Net change in cash, cash equivalents and restricted cash		(350	)		64,649
Cash, cash equivalents and restricted cash, beginning of period		6,392			15,373
Cash, cash equivalents and restricted cash, end of period	$	6,042		$	80,022

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

9

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY (PREDECESSOR)

(In thousands)

	Partner's Equity
	Limited Partners
	Common Units
Balance at December 31, 2016 (Predecessor)		99,489
Net income (loss)		(16,377	)
Amortization of unit-based awards		1,069
Restricted units repurchased and other		(1	)
Balance at March 31, 2017 (Predecessor)	$	84,180

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY (SUCCESSOR)

(In thousands)

	Stockholders' Equity
	Common Stock		Warrants		Additional Paid-in Capital			Accumulated Earnings (Deficit)		Total
Balance at December 31, 2017 (Successor)	$	3	$	4,788	$	387,856		$	1,286	$	393,933
Net income (loss)		—		—		—			3,239		3,239
Share-based compensation expense		—		—		1,176			—		1,176
Other		—		—		(208	)		—		(208	)
Balance at March 31, 2018 (Successor)	$	3	$	4,788	$	388,824		$	4,525	$	398,140

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

10

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED 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 the economic environments are not different 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.

Emergence from Voluntary Reorganization under Chapter 11

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). On April 14, 2017, the Bankruptcy Court entered an 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.

Basis of Presentation

Our Unaudited Condensed Consolidated Financial Statements included herein have been prepared pursuant to the rules and guidelines of the Securities and Exchange Commission (the “SEC”). The results reported in these Unaudited Condensed Consolidated Financial Statements should not necessarily be taken as indicative of results that may be expected for the entire year. In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the SEC.

The Unaudited Condensed Consolidated 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 Unaudited Condensed Statements of Consolidated Operations.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated financial statements.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Comparability of Financial Statements to Prior Periods

We 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”), on May 4, 2017. Accordingly, our Unaudited Condensed Consolidated Financial Statements and Notes after May 4, 2017, are not comparable to the Unaudited Condensed Consolidated Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Unaudited Condensed Consolidated 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 Unaudited Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor.

Use of Estimates

The preparation of the accompanying Unaudited Condensed Consolidated 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 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.  

Note 2. Summary of Significant Accounting Policies

A discussion of our significant accounting policies and estimates is included in our 2017 Form 10-K.

Accrued Liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

	Successor		Successor
	March 31,		December 31,
	2018		2017
Accrued lease operating expense	$	7,840	$	6,439
Accrued capital expenditures		4,591		3,854
Accrued general and administrative expense		3,515		4,412
Accrued ad valorem tax		754		398
Asset retirement obligation		438		713
Accrued interest payable		166		1,309
Other		—		1,108
Accrued liabilities	$	17,304	$	18,233

Cash and Cash Equivalents Reconciliation

The following table provides a reconciliation of cash and cash equivalents on the Unaudited Condensed Consolidated Balance Sheet to cash, cash equivalents and restricted cash on the Unaudited Condensed Statements of Consolidated Cash Flows (in thousands):

	Successor		Successor
	March 31,		December 31,
	2018		2017
Cash and cash equivalents	$	5,717	$	6,392
Restricted cash		325		—
Total cash, cash equivalents and restricted cash	$	6,042	$	6,392

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flows

Supplemental cash flows for the periods presented (in thousands):

	Successor		Predecessor
	For the Three		For the Three
	Months Ended		Months Ended
	March 31, 2018		March 31, 2017
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	6,028	$	4,777
Cash paid for reorganization items, net		656		3,887
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		1,890		912

Reorganization Items, Net

The Company has incurred significant costs associated with the reorganization. Reorganization items, net, which are expensed as incurred, 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 Unaudited Condensed Statements of Consolidated Operations (in thousands):

	Successor			Predecessor
	For the Three			For the Three
	Months Ended			Months Ended
	March 31, 2018			March 31, 2017
Professional fees	$	(414	)	$	(7,585	)
Other		(104	)		(68	)
Reorganization items, net	$	(518	)	$	(7,653	)

Revenue Recognition

In May 2014, the Financial Accounting Standards Board (“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 we expect to be entitled to in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance and requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The standard was effective for the Company starting January 1, 2018, and the Company adopted the standard using a modified retrospective approach. See Note 3 for additional information.

New Accounting Pronouncements

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. 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.

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 amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company is the lessee under various agreements for office space, compressors, equipment, and surface rentals that are currently accounted for as operating leases. 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 quantitative impacts of the new standard are dependent on the leases in place at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods.

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 3. Revenue

Revenue from contracts with customers

As discussed in Note 2, the Company adopted Accounting Standard Update (ASU) No. 2014-09, revenue from contracts with customers (ASC 606), on January 1, 2018 using the modified retrospective method of adoption. Adoption of the ASU did not require an adjustment to the opening balance of equity and did not materially change the Company's amount and timing of revenues. The Company applied the ASU only to contracts that were not completed as of January 1, 2018.

Although the adoption of ASC 606 did not have an impact on the Company’s net income or cash flows, it did result in the reclassification of fees incurred under certain gathering and gas processing agreements. Such reclassification led to an overall decrease in oil and natural gas sales with a corresponding decrease in gathering, processing and transportation as follows (in thousands):

	For the Three Months Ended
	March 31, 2018
	As Reported		Previous Revenue Recognition Method		Increase/ (Decrease)
	(in thousands)
Revenues:
Oil and natural gas sales	$	87,847	$	88,698	$	(851	)
Cost and expenses:
Gathering, processing and transportation		5,600		6,451		(851	)
Net income (loss)	$	3,239	$	3,239	$	—

The reclassification of certain fees between oil and natural gas sales and gathering, processing and transportation is the result of the Company’s assessment of the point in time at which its performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as gathering, processing and transportation and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered.

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 March 31, 2018 and 2017.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Disaggregation of Revenue

We have identified three material revenue streams in our business: oil, natural gas and NGLs. The following table present our revenues disaggregated by revenue stream.

	For the Three Months Ended
	March 31, 2018
	(in thousands)
Revenues
Oil	$	54,726
NGLs		10,946
Natural gas		22,175
Oil and natural gas sales	$	87,847

Contract Balances

Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $29.4 million at March 31, 2018 which includes $1.1 million that has been reclassified to assets held for sale and $30.1 million at December 31, 2017.

Transaction Price Allocated to Remaining Performance Obligations

For our contracts that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our contracts that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Note 4. Acquisitions and Divestitures

Acquisition and Divestiture Related Expenses

Acquisition and divestiture related expenses for both related party and third party transactions are included in general and administrative expense in the accompanying Unaudited Condensed Statements of Consolidated Operations for the periods indicated below (in thousands):

Successor		Predecessor
For the Three		For the Three
Months Ended		Months Ended
March 31, 2018		March 31, 2017
$	208	$	—

Acquisitions and Divestitures

There were no material acquisitions or divestitures during the three months ended March 31, 2018 and 2017, respectively.

Assets Held for Sale

On March 9, 2018, we entered into a definitive agreement to divest certain of our non-core assets in South Texas (the “South Texas Divestiture”). The assets held for sale are recorded at the lower of their carrying value or fair value less cost to sell. We recorded a loss as a result of the planned disposal of approximately $2.4 million during the three months ended March 31, 2018 in “(gain) loss on sale of properties” in the accompanying Unaudited Condensed Statements of Consolidated Operations. This disposition did not qualify as a discontinued operation. The major categories of assets and liabilities were:

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Successor
	March 31, 2018
	(In thousands)
Assets classified as held for sale
Accounts receivable	$	2,036
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		39,057
Accumulated depreciation, depletion, and impairment		(5,124	)
Property and equipment, net		33,933
Total assets classified as held for sale	$	35,969
Liabilities associated with assets held for sale
Current liabilities:
Revenue payable	$	(517	)
Accrued liabilities		(585	)
Total current liabilities		(1,102	)
Asset retirement obligations		(15,409	)
Total liabilities associated with assets held for sale	$	(16,511	)

Note 5. 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). All of the derivative instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets were considered Level 2.

The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying Unaudited Condensed Consolidated Balance Sheets approximated fair value at March 31, 2018 and December 31, 2017. 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair market values of the derivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 were based on estimated forward commodity prices. 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 gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2018 and December 31, 2017 for each of the fair value hierarchy levels:

	Successor
	Fair Value Measurements at March 31, 2018 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	$	—	$	28,864	$	—	$	28,864
Liabilities:
Commodity derivatives	$	—	$	21,120	$	—	$	21,120

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	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

See Note 6 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 accompanying Unaudited Condensed Consolidated 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 factors such 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 7 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.

• Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of 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 natural 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.

• No impairments were recognized during the three months ended March 31, 2018 or 2017, respectively.

Note 6. 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 and borrowing related activities. These instruments limit exposure to declines in prices, but also limit the benefits that would be realized if prices increase.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Certain inherent business risks are associated with commodity 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 March 31, 2018, 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 had the right to offset $13.9 million against amounts outstanding under our Credit Facility at March 31, 2018. See Note 7 for additional information regarding our Credit Facility (as defined below).

Commodity Derivatives

We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, and costless collars) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value.

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.

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 ICE Brent. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At March 31, 2018, we had the following open commodity positions:

	Remaining
	2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (MMBtu)		1,802,000		1,250,000
Weighted-average fixed price	$	3.54	$	2.82
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		205,000		186,000
Weighted-average fixed price	$	69.14	$	54.08
NGL Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		86,800		72,000
Weighted-average fixed price	$	25.85	$	29.96

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 2018 and December 31, 2017. 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						Successor
		Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
		March 31,			March 31,			December 31,			December 31,
Type	Balance Sheet Location	2018			2018			2017			2017
		(In thousands)
Commodity contracts		$	27,009		$	14,020		$	37,729		$	9,183
Gross fair value			27,009			14,020			37,729			9,183
Netting arrangements			(11,347	)		(11,347	)		(9,183	)		(9,183	)
Net recorded fair value	Short-term derivative instruments	$	15,662		$	2,673		$	28,546		$	—
Commodity contracts		$	1,855		$	7,100		$	459		$	5,929
Gross fair value			1,855			7,100			459			5,929
Netting arrangements			(1,699	)		(1,699	)		(459	)		(459	)
Net recorded fair value	Long-term derivative instruments	$	156		$	5,401		$	—		$	5,470

(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 Unaudited Condensed Statements of Consolidated Operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):

	Successor		Predecessor
	For the Three		For the Three
	Months Ended		Months Ended
	March 31, 2018		March 31, 2017
(Gain) loss on commodity derivatives	$	10,456	$	(10,241	)

Note 7. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the Company’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2018 (in thousands):

Asset retirement obligations at beginning of period (Successor)	$	100,173
Liabilities added from acquisition or drilling		53
Liabilities settled		—
Accretion expense		1,718
Revision of estimates (1)		(13,407	)
Asset retirement obligation at end of period		88,537
Less: Current portion		(438	)
Less: Current portion - Assets held for sale		(275	)
Less: Long-term portion - Assets held for sale		(15,409	)
Asset retirement obligations - long-term portion (Successor)	$	72,415

(1) The decrease in revision of estimates during the three months ended March 31, 2018 is primarily due to receiving new cost estimates from third parties regarding the estimated plugging and abandonment costs.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Long-Term Debt

The following table presents our consolidated debt obligations at the dates indicated:

	Successor		Successor
	March 31,		December 31,
	2018		2017
	(In thousands)
$1.0 billion Credit Facility, variable-rate, due March 2021 (1)	$	347,000	$	376,000
Long-term debt	$	347,000	$	376,000

(1) The carrying amount of our Credit Facility approximates fair value because the interest rates are variable and reflective of market rates.

OLLC Revolving Credit Facility

Amplify Energy Operating LLC, our wholly owned subsidiary, is a party to a $1.0 billion revolving credit facility (our “Credit Facility”) which is guaranteed by us and all of our current subsidiaries.

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. The borrowing base as of March 31, 2018 was approximately $440.0 million.

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 our Credit Facility.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid, excluding commitment fees, on our consolidated variable-rate debt obligations for the periods presented:

	Successor	Predecessor
	For the Three	For the Three
	Months Ended	Months Ended
	March 31, 2018	March 31, 2017
Credit Facility	5.48%	n/a
Predecessor's revolving credit facility	n/a	4.13%

Letters of Credit

At March 31, 2018, we had $2.4 million of letters of credit outstanding, primarily related to operations at our Wyoming properties.

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with our Credit Facility was $6.6 million at March 31, 2018. The unamortized deferred financing costs are amortized over the remaining life of our Credit Facility.

Note 9. Equity (Deficit)

Common Stock

The Company’s authorized capital stock includes 300,000,000 shares of common stock, $0.0001 par value per share. The following is a summary of the changes in our common stock issued for the three months ended March 31, 2018:

	Common
	Shares
Balance, December 31, 2017 (Successor)		25,000,000
Issuance of common stock		—
Restricted stock units vested		23,200
Repurchase of common shares		(23,200	)
Balance, March 31, 2018 (Successor)		25,000,000

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Management Incentive Plan (the “MIP”)), exercisable for a five-year period commencing on the Effective Date at an exercise price of $42.60 per share.

Note 10. 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 share/unit amounts):

	Successor			Predecessor
	For the Three			For the Three
	Months Ended			Months Ended
	March 31, 2018			March 31, 2017
Net income (loss) attributable to Successor/Predecessor	$	3,239		$	(16,377	)
Less: Net income allocated to participating restricted stockholders		(83	)		—
Basic and diluted earnings available to common stockholders/limited partners	$	3,156		$	(16,377	)
Common shares/units:
Common shares/units outstanding — basic		25,000			83,810
Dilutive effect of potential common shares/units		—			—
Common shares/units outstanding — diluted		25,000			83,810
Net earnings per share/unit:
Basic	$	0.13		$	(0.20	)
Diluted	$	0.13		$	(0.20	)
Antidilutive stock options (1)		513			—
Antidilutive warrants (2)		2,174			—

(1) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

(2) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

Note 11. Long-Term Incentive Plans

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 were 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 (the “Board”).

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 $6.2 million at March 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.1 years.

21

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 December 31, 2017 (Successor)		682,792		$	13.54
Granted		—		$	—
Forfeited		(14,893	)	$	12.71
Vested		(23,200	)	$	13.77
Restricted stock units outstanding at March 31, 2018 (Successor)		644,699		$	13.55

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

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.

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 March 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.2 years.

The following table summarizes information regarding the restricted stock awards granted under the Directors Compensation Plan.

			Weighted-
			Average Grant
	Number of		Date Fair Value
	Units		per Unit (1)
Restricted stock units outstanding at December 31, 2017 (Successor)		16,341	$	13.77
Granted		—	$	—
Forfeited		—	$	—
Vested		—	$	—
Restricted stock units outstanding at March 31, 2018 (Successor)		16,341	$	13.77

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

Restricted Stock Options

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 $1.8 million at March 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.1 years.

No restricted stock options were granted during the three months ended March 31, 2018.

22

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 December 31, 2017 (Successor)		517,398		$	5.01
Granted		—		$	—
Forfeited		(4,300	)	$	5.01
Vested		—		$	—
Restricted stock options outstanding at March 31, 2018 (Successor)		513,098		$	5.01

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

Compensation Expense

The following table summarizes the amount of recognized compensation expense associated with the MIP and Memorial Production Partners GP LLC Long Term Incentive Plan awards that are reflected in the accompanying Unaudited Condensed Statements of Consolidated Operations for the periods presented (in thousands):

	Successor		Predecessor
	For the Three		For the Three
	Months Ended		Months Ended
	March 31, 2018		March 31, 2017
Equity classified awards
Restricted stock units (Successor)	$	967	$	—
Restricted stock options (Successor)		209		—
Restricted common units (Predecessor)		—		1,069
Liability classified awards
Phantom units (Predecessor)		—		56
	$	1,176	$	1,125

Note 12. Related Party Transactions

Related Party Agreements

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 for the three months ended March 31, 2018 or 2017, respectively.

Note 13. Commitments and Contingencies

Litigation and 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.

23

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At March 31, 2018 and December 31, 2017, we had no environmental reserves recorded on our Unaudited Condensed Consolidated Balance Sheet.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

Beta Operating Company, LLC, has an obligation with the BOEM in connection with its 2009 acquisition of our properties in offshore Southern California. The trust account had the required minimum balance of $152.0 million at March 31, 2018 and December 31, 2017 and is fully cash funded. The held-to-maturity investments held in the trust account at March 31, 2018 for the U.S. Bank money market cash equivalent was $152.3 million.

In 2015, the Bureau of Safety and Environmental Enforcement issued a preliminary report that indicated the estimated costs 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 mid-2018.

Note 14. Income Taxes

Effective May 5, 2017, pursuant to the Plan, the Successor became a corporation subject to federal and state income taxes. Prior to the Plan being effective, the Predecessor was a limited partnership and organized as a pass-through entity for federal and most state income tax purposes. As a result, our Predecessor limited partners were responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries were taxed as corporations for federal and state income tax purposes, which resulted in deferred taxes. We were also subject to the Texas margin tax for partnership activity in the state of Texas.

The Company’s had no income tax benefit/(expense) for the three months ended March 31, 2018 and had an income tax benefit/(expense) of $0.1 million for the three months ended March 31, 2017. The Company’s effective tax rate was 0.0% and 0.6% for the three months ended March 31, 2018 and 2017, respectively. The effective tax rate for the three months ended March 31, 2018 is different from the statutory U.S. federal income tax rate primarily due to our existing valuation allowances. The effective tax rate for the three months ended March 31, 2017 is different from the statutory U.S. federal income tax rate primarily due to the Predecessor not being subject to U.S. federal income tax.

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) temporary bonus depreciation that will allow for full expensing of qualified property, (3) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80 percent of taxable income, and (4) elimination of certain business deductions and credits, including the deduction for entertainment expenditures. 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 allows us to record provisional amounts during a measurement period not to extend beyond one year of the enactment date. We have reported provisional amounts for the income tax effects of the Tax Act for which the accounting is incomplete but a reasonable estimate could be determined. As of March 31, 2018, we have not changed the provisional amounts recorded in 2017. Based on a continued analysis of the estimates, revisions may occur during the allowable measurement period.

Note 15. Subsequent Events

Management Changes

On May 1, 2018, the Company announced the retirement of William J. Scarff, the Company’s President and Chief Executive Officer and a member of the Board, effective as of the earlier of May 17, 2018 (or a later mutually agreed date) and (ii) the date on which his successor is appointed (the “CEO Retirement Date”), provided that he will continue to serve as a member of the Board. Also on May 1, 2018, the Company announced the departure of Christopher S. Cooper, Senior Vice President and Chief Operating Officer, and Robert L. Stillwell, Jr., Senior Vice President and Chief Financial Officer, from their respective positions with the Company effective April 27, 2018. There were no disagreements between the Company and any of Messrs. Scarff, Cooper or Stillwell (collectively, the “Departing Executives”) which led to their retirement or separation (as applicable) from the Company.

On April 27, 2018, the Board appointed Martyn Willsher to serve as Senior Vice President and Chief Financial Officer of the Company effective April 27, 2018.

On May 4, 2018, the Board appointed Kenneth Mariani to serve as President and Chief Executive Officer of the Company effective May 14, 2018.

24

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Retirement and Separation Agreements with Certain Officers

In connection with his retirement from his positions as President and Chief Executive Officer of the Company, Mr. Scarff and the Company entered into a retirement agreement (the “Retirement Agreement”) on April 27, 2018. In addition, on April 27, 2018, the Company entered into separation agreements with each of Messrs. Cooper and Stillwell (each, a “Separation Agreement,” and collectively with the Retirement Agreement, the “Agreements”).

Pursuant to their respective Agreements, each Departing Executive provided irrevocable releases of claims in favor of the Company and its affiliates and related persons and entities through the date signed, and also acknowledged existing restrictive covenants with the Company, including non-competition, non-solicitation and confidentiality covenants. In addition, pursuant to their respective Agreements:

(i) prior to the CEO Retirement Date, Mr. Scarff will continue to receive his current base salary and will remain eligible to participate in the Company’s retirement and health and welfare plans in accordance with the terms and conditions of such plans;

(ii) subject to certain conditions, each Departing Executive will receive retirement or separation payments (as applicable) consisting of: (A) the cash severance payment and other amounts due to him under his respective severance agreement with the Company; (B) accelerated vesting of his option to purchase the number of shares of the Company’s common stock as previously granted to him under the MIP; and (C) subject to certain limitations and transfer restrictions, the right to elect to receive either an additional cash payment as set forth in the table below (less applicable withholdings and deductions) or the number of shares of the Company’s common stock as set forth in the table below; and

(iii) subject to limited exceptions, the Departing Executives will no longer be eligible to vest in the restricted stock unit awards previously granted to them under the MIP.

	Election to Receive Either
Departing Executives	Additional Cash Payment		Shares of Common Stock
William J. Scarff	$	296,594		41,951
Christopher S. Cooper	$	207,384		29,333
Robert L. Stillwell, Jr.	$	155,540		22,000

The foregoing description of the Retirement Agreement and Separation Agreements does not purport to be complete and is qualified in its entirety by reference to the Retirement Agreement and Separation Agreements, which will be filed as exhibits to the Company’s Quarterly Report on Form 10-Q for the three months ending June 30, 2018. In addition, investors should review the form of severance agreement, which is filed as Exhibit 10.16 to the 2017 Form 10-K.

Grants of Restricted Stock Units

On April 27, 2018, the Board approved grants of restricted stock unit awards (the “Awards”) to certain of the Company’s executive officers under the MIP. Subject to the terms and conditions of the applicable award agreements, the Awards 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 number of restricted stock units issuable to the Company’s executive officers under the applicable award agreements is set forth below:

Executive Officers	Restricted Stock Units
Martyn Willsher Senior Vice President and Chief Financial Officer		11,500
Matthew J. Hoss Vice President and Chief Accounting Officer		10,000
Richard P. Smiley Vice President of Operations - Onshore		10,000

The foregoing description of the Awards does not purport to be complete and is qualified in its entirety by reference to the MIP and the form of restricted stock unit award agreement, which are filed as Exhibits 10.8 and 10.10, respectively, to the 2017 Form 10-K.

Application for Final Decree

On April 30, 2018, the Debtors filed with the Bankruptcy Court a motion for a final decree and entry of an order closing the chapter 11 cases with respect to each of the Debtors other than (i) San Pedro Bay Pipeline Company, Ch. 11 Case No. 17-30249, (ii) Rise Energy Beta, LLC, Ch. 11 Case No. 17-30250, and (iii) Beta Operating Company, LLC, Ch. 11 Case No. 17-30253. A hearing to consider approval of the motion has been scheduled for June 18, 2018.

25

ITEM 2. 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 Unaudited Condensed Consolidated Financial Statements and accompanying notes in “Item 1. Financial Statements” contained herein and our Annual Report on Form 10-K for the year ended December 31, 2017, filed with the SEC on March 12, 2018 (“2017 Form 10-K”). 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. See “Cautionary Note Regarding 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 Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017, and MEMP’s consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

Overview

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 Amplify Energy Operating LLC (“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

Management Changes

On May 1, 2018, we announced the retirement of William J. Scarff, our President and Chief Executive Officer and a member of the board of directors, effective as of the earlier of May 17, 2018 (or a later mutually agreed date) and (ii) the date on which his successor is appointed, provided that he will continue to serve as a member of the board. Also on May 1, 2018, we announced the departure of Christopher S. Cooper, our Senior Vice President and Chief Operating Officer, and Robert L. Stillwell, Jr., our Senior Vice President and Chief Financial Officer, from their respective positions with the Company effective April 27, 2018.

There were no disagreements between us and any of Messrs. Scarff, Cooper or Stillwell which led to their retirement or separation (as applicable) from the Company.

On April 27, 2018, the board of directors appointed Martyn Willsher to serve as our Senior Vice President and Chief Financial Officer effective April 27, 2018.

On May 4, 2018, the Board appointed Kenneth Mariani to serve as President and Chief Executive Officer of the Company effective May 14, 2018.

See Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” for additional information.

26

Divestiture Processes

In March 2018, the Company entered into a definitive agreement to sell its interest in properties located in South Texas for a contract price of $20.0 million, subject to closing adjustments.

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.

Appointment of Director

In March 2018, David M. Dunn was appointed to the board of directors. Mr. Dunn has been appointed to the audit committee and the compensation committee of the board of directors.

Reduction in Force

In February 2018 and March 2018, certain employees were impacted by a workforce reduction resulting in the involuntary termination of 30 employees across the Company.

Predecessor and Successor Reporting

As a result of the application of fresh start accounting, the Company’s Unaudited Condensed Consolidated Financial Statements and certain note presentations are separated into two distinct periods, the period before and through May 4, 2017 (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.

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 (defined below).

Sources of Revenues

Our revenues are derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from natural gas during processing. Production revenues are derived entirely from the continental United States. Natural gas, NGL and oil prices are inherently volatile and are influenced by many factors outside our control. In order to reduce the impact of fluctuations in natural gas and oil prices on revenues, we intend to periodically enter into derivative contracts that fix the future prices received. At the end of each period the fair value of these commodity derivative instruments are estimated and because hedge accounting is not elected, the changes in the fair value of unsettled commodity derivative instruments are recognized in earnings at the end of each accounting period.

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 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 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 give the businesses the right to be chartered or operate within that state.

27

• Depreciation, depletion and amortization. Depreciation, depletion and amortization, or 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 properties. Proved properties are impaired whenever the carrying value of the properties exceeds 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.

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

• Interest expense. We finance a portion of our working capital requirements, capital development and acquisitions with borrowings under our Credit Facility and our Predecessor’s revolving credit facility. 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 three months ended March 31, 2017, 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.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2017 Form 10-K. 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. These estimates, in our opinion, are subjective in nature, require the use of professional judgment and involve complex analysis.

When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Results of Operations

The results of operations for the three months ended March 31, 2018 and 2017 have been derived from our consolidated financial statements.

28

The following table summarizes certain of the results of operations for the periods indicated.

	Successor				Predecessor
	For the Three				For the Three
	Months Ended				Months Ended
	March 31, 2018				March 31, 2017
	(In thousands)				(In thousands)
Oil and natural gas sales	$	87,847			$	81,284
Lease operating expense		29,570				25,986
Gathering, processing and transportation		5,600				8,035
Taxes other than income		5,037				4,266
Depreciation, depletion and amortization		12,958				27,882
General and administrative expense		10,657				23,370
Accretion of asset retirement obligations		1,718				2,495
(Gain) loss on commodity derivative instruments		10,456				(10,241	)
(Gain) loss on sale of properties		2,373		��		—
Interest expense, net		(5,772	)			(8,400	)
Reorganization items, net		(518	)			(7,653	)
Income tax benefit (expense)		—				91
Net income (loss)		3,239				(16,377	)
Oil and natural gas revenue:
Oil sales	$	54,726			$	41,301
NGL sales		10,946				10,608
Natural gas sales		22,175				29,375
Total oil and natural gas revenue	$	87,847			$	81,284
Production volumes:
Oil (MBbls)		902				889
NGLs (MBbls)		412				456
Natural gas (MMcf)		7,775				9,238
Total (MMcfe)		15,660				17,311
Average net production (MMcfe/d)		174.0				192.3
Average sales price:
Oil (per Bbl)	$	60.66			$	46.45
NGL (per Bbl)		26.57				23.25
Natural gas (per Mcf)		2.85				3.18
Total (per Mcfe)	$	5.61			$	4.70
Average unit costs per Mcfe:
Lease operating expense	$	1.89			$	1.50
Gathering, processing and transportation		0.36				0.46
Taxes other than income		0.32				0.25
General and administrative expense		0.68				1.35
Depletion, depreciation and amortization		0.83				1.61

For the Three Months Ended March 31, 2018 and the Three Months Ended March 31, 2017

Net income of $3.2 million and $16.4 million was recorded for the three months ended March 31, 2018 and 2017, respectively.

• Oil, natural gas and NGL revenues were $87.8 million and $81.3 million for the three months ended March 31, 2018 and 2017, respectively. Average net production volumes were approximately 174.0 MMcfe/d and 192.3 MMcfe/d for the three months ended March 31, 2018 and 2017, respectively. The change in production volumes was primarily due to decreased drilling activity. The average realized sales price was $5.61 per Mcfe and $4.70 per Mcfe for the three months ended March 31, 2018 and 2017, respectively. The increase was primarily due to increases in realized prices for oil and NGLs.

• Lease operating expense was $29.6 million and $26.0 million for the three months ended March 31, 2018 and 2017, respectively. On a per Mcfe basis, lease operating expense was $1.89 and $1.50 for the three months ended March 31, 2018 and 2017, respectively. The change in lease operating expense on a per Mcfe basis was primarily due to lower production and higher workover expenses.

• Gathering, processing and transportation was $5.6 million and $8.0 million for the three months ended March 31, 2018 and 2017, respectively. The change in gathering, processing and transportation was primarily a result of lower production and the impact of the new accounting standard related to revenue from contracts with customers adopted on January 1, 2018. On a per Mcfe basis, gathering, processing and transportation were $0.36 and $0.46 for each of the three months ended March 31, 2018 and 2017, respectively.

29

• Taxes other than income were $5.0 million and $4.3 million for the three months ended March 31, 2018 and 2017, respectively. On a per Mcfe basis, taxes other than income were $0.32 and $0.25 for the three months ended March 31, 2018 and 2017, respectively. The change in taxes other than income on a per Mcfe basis was due to an increase in commodity price.

• DD&A expense was $13.0 million and $27.9 million for the three months ended March 31, 2018 and 2017, 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.

• General and administrative expense was $10.7 million and $23.4 million for the three months ended March 31, 2018 and 2017, respectively. Non-cash share/unit-based compensation expense was approximately $1.2 million and $1.1 million for the three months ended March 31, 2018 and 2017, respectively. During the three months ended March 31, 2017, we recorded $7.6 million in pre-petition restructuring-related costs primarily for advisory and professional fees and $5.1 million in higher bonus expense.

• Net losses on commodity derivative instruments of $10.5 million were recognized for the three months ended March 31, 2018, consisting of $4.8 million of cash settlement receipts on expired positions offset by a $15.3 million decrease in the fair value of open positions. Net gains on commodity derivative instruments of $10.2 million were recognized for the three months ended March 31, 2017, consisting of $10.8 million of cash settlement receipts on expired positions and $94.1 million of cash settlement receipts on terminated derivatives. These gains were partially offset by a $94.7 million decrease in the fair value of open positions.

Given the volatility of commodity prices, it is not possible to predict future reported 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 partially 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.

• Interest expense, net was $5.8 million and $8.4 million for the three months ended March 31, 2018 and 2017, respectively. The change in interest expense is primarily due to $3.5 million in interest expense for the Predecessor’s 7.625% senior notes due May 2021 and 6.875% senior notes due August 2022 (collectively, the “Notes”) recognized for the three months ended March 31, 2017. The Notes were cancelled on the Effective Date.

Average outstanding borrowings under our Credit Facility were $364.2 million for the three months ended March 31, 2018. Average outstanding borrowings under our Predecessor’s revolving credit facility were $462.6 million for the three months ended March 31, 2017. We had an average of $1.1 billion aggregate principal amount of the Notes issued and outstanding for the three months ended March 31, 2017.

• The Company has incurred significant costs associated with the reorganization. Reorganization items, net represents costs and income directly associated with the Company’s Chapter 11 proceedings since January 16, 2017, the petition date, such as advisor and professional fees. The Company incurred $0.5 million and $7.7 million of reorganization items, net for the three months ended March 31, 2018 and 2017, respectively.

Adjusted EBITDA

We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our reconciliation of Adjusted EBITDA to net income and net cash flows from operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

• Interest expense;

• Income tax expense;

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

• 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;

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• Losses on sale of assets;

• Share/unit based compensation expenses;

• Exploration costs;

• Acquisition and divestiture related expenses;

• Restructuring related costs;

• Reorganization items, net; and

• Other non-routine items that we deem appropriate.

Less:

• Interest income;

• Income tax benefit;

• Gain on 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 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 available to develop existing reserves or acquire additional oil and natural gas properties.

The following tables present our reconciliation of Adjusted EBITDA to net income and net cash flows from operating activities, our most directly comparable GAAP financial measures, for each of the periods indicated.

Reconciliation of Adjusted EBITDA to Net Income (Loss)

	Successor		Predecessor
	For the Three		For the Three
	Months Ended		Months Ended
	March 31, 2018		March 31, 2017
	(In thousands)		(In thousands)
Net income (loss)	$	3,239	$	(16,377	)
Interest expense, net		5,772		8,400
Income tax expense (benefit)		—		(91	)
DD&A		12,958		27,882
Accretion of AROs		1,718		2,495
(Gains) losses on commodity derivative instruments		10,456		(10,241	)
Cash settlements received (paid) on expired commodity derivative instruments		4,876		10,826
(Gain) loss on sale of properties		2,373		—
Acquisition and divestiture related expenses		208		—
Share/Unit based compensation expense		1,176		1,125
Exploration costs		34		16
(Gain) loss on settlement of AROs		—		(8	)
Restructuring related costs		—		7,548
Reorganization items, net		518		7,653
Other		—		42
Adjusted EBITDA	$	43,328	$	39,270

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Reconciliation of Adjusted EBITDA to Net Cash from Operating Activities

	Successor			Predecessor
	For the Three			For the Three
	Months Ended			Months Ended
	March 31, 2018			March 31, 2017
	(In thousands)			(In thousands)
Net cash provided by (used in) operating activities	$	42,147		$	125,765
Changes in working capital		(4,810	)		(12,288	)
Interest expense, net		5,772			8,400
Cash settlements received on terminated derivatives		—			(94,146	)
Amortization of deferred financing fees		(541	)		—
Acquisition and divestiture related expenses		208			—
Income tax expense (benefit) - current portion		—			(17	)
Exploration costs		34			16
Plugging and abandonment cost		—			105
Restructuring related costs		—			7,548
Reorganization items, net		518			3,887
Adjusted EBITDA	$	43,328		$	39,270

Liquidity and Capital Resources

Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, meet our indebtedness obligations, refinance our indebtedness or 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 and equity and debt capital markets. For the remainder of 2018, we expect our primary funding sources to be cash flows generated by operating activities, available borrowing capacity under our Credit Facility and/or the divestiture 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 March 31, 2018, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit 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 $14.9 million for the three months ended March 31, 2018, which were primarily related to drilling, capital workovers and facilities located in East 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 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 mid-2018. At March 31, 2018, there was approximately $152.3 million in the trust account and $62.0 million in surety bonds.

Working Capital. We expect to fund our working capital needs primarily with operating cash flows. We also plan to reinvest a sufficient amount of our operating cash flow to fund our expected capital expenditures. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements. See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” and “— Overview” of this quarterly report for additional information.

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As of March 31, 2018, we had working capital of $13.5 million primarily due to an accounts receivable balance of $31.5 million and a current derivative asset balance of $15.7 million partially offset by accrued liabilities of $17.3 million and revenues payable of $23.4 million.

Debt Agreements

Credit Facility. On May 4, 2017, OLLC, as borrower, entered into the Credit Agreement 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. The borrowing base as of March 31, 2018, was approximately $440.0 million.

As of March 31, 2018, 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 March 31, 2018, we had approximately $90.6 million of available borrowings under our Credit Facility, net of $2.4 million in letters of credit. See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding the Credit Facility.

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 three months ended March 31, 2018 and 2017 have been derived from our Unaudited Condensed Consolidated Financial Statements. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated Cash Flows included under “Item 1. Financial Statements” of this quarterly report.

	Successor			Predecessor
	For the Three			For the Three
	Months Ended			Months Ended
	March 31, 2018			March 31, 2017
	(In thousands)			(In thousands)
Net cash provided by operating activities	$	42,147		$	125,765
Net cash (used in) investing activities		(13,284	)		(4,262	)
Net cash provided by (used in) financing activities		(29,213	)		(56,854	)

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $42.1 million and $125.8 million for the three months ended March 31, 2018 and 2017, respectively. Production volumes were approximately 174.0 MMcfe/d and 192.3 MMcfe/d for the three months ended March 31, 2018 and 2017, respectively. The average realized sales price was $5.61 per Mcfe and $4.70 per Mcfe for the three months ended March 31, 2018 and 2017, respectively. Lease operating expenses were $29.6 million and $26.0 million for the three months ended March 31, 2018 and 2017, respectively. Gathering, processing and transportation was $5.6 million and $8.0 million for the three months ended March 31, 2018 and 2017, respectively. Cash settlements received on terminated derivatives were $94.1 million for the three months ended March 31, 2017.

Investing Activities. Net cash used in investing activities for the three months ended March 31, 2018 was $13.3 million, of which $13.1 million was used for additions to oil and natural gas properties. Net cash used in investing activities for the three months ended March 31, 2017 was $4.3 million, of which $3.9 million was used for additions to oil and natural gas properties.

Financing Activities. The Company had net repayments of $29.0 million under the Credit Facility for the three months ended March 31, 2018. The Company had net repayments of $56.9 million under the Predecessor’s revolving credit facility for the three months ended March 31, 2017.

Contractual Obligations

During the three months ended March 31, 2018, there were no significant changes in our consolidated contractual obligations from those reported in our 2017 Form 10-K except for the Credit Facility borrowings and repayments.

Off–Balance Sheet Arrangements

As of March 31, 2018, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

In the normal course of our business operations, we are exposed to certain risks, including commodity prices. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. We believe that our exposures to market risk have not changed materially since those reported under Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2017 Form 10-K.

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.

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 Mach 31, 2018, see Note 6 of the Notes to Unaudited Condensed Consolidated Financial Statements included “Item 1. Financial Statements” of this quarterly report.

Counterparty and Customer Credit Risk

We are also 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 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 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 March 31, 2018, 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 had the right to offset $13.9 million against amounts outstanding under our Credit Facility at March 31, 2018.

ITEM 4. 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, 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 quarterly 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, 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 the evaluation, the principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2018.

Change in Internal Control Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended March 31, 2018 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 quarterly report.

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, “Item 1. Financial Statements,” Note 13, “Commitments and Contingencies — Litigation and Environmental” of the Notes to Unaudited Condensed Consolidated Financial Statements included in this quarterly report, which is incorporated herein by reference.

ITEM 1A. RISK FACTORS.

Our business faces many risks. Any of the risks discussed elsewhere in this quarterly report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. There have been no material changes with respect to the risk factors since those disclosed in our 2017 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

The following table summarizes our repurchase activity during the three months ended March 31, 2018:

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs
						(In thousands)
Common Shares Repurchased (1)
January 1, 2018 - January 31, 2018 (Successor)		—	$	—	n/a	n/a
February 1, 2018 - February 28, 2018 (Successor)		23,200	$	11.00	n/a	n/a
March 1, 2018 - March 31, 2018 (Successor)		—	$	—	n/a	n/a

(1) Common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. The Company repurchased the remaining vesting shares on the vesting date at current market price. See Note 9 of the Notes to the Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

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).
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).
31.1*	—	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

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Exhibit Number		Description
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.
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 as an exhibit to this Quarterly Report on Form 10-Q.

** Furnished as an exhibit to this Quarterly Report on Form 10-Q.

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SIGNATURES

Pursuant to the requirements 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: May 9, 2018	By:	/s/ Martyn Willsher.
	Name:	Martyn Willsher
	Title:	Senior Vice President and Chief Financial Officer

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