ampy-10q_20180930.htm

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ 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.

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 November 2, 2018, the registrant had 25,072,856 outstanding shares of common stock, $0.0001 par value outstanding.

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.

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.

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.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

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.

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.

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:

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:

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.

	Successor			Successor
	September 30,			December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	11,862		$	6,392
Restricted cash		325			—
Accounts receivable		28,833			36,391
Short-term derivative instruments		996			28,546
Prepaid expenses and other current assets		6,283			7,220
Total current assets		48,299			78,549
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		593,361			603,053
Support equipment and facilities		103,569			100,225
Other		6,300			6,133
Accumulated depreciation, depletion and impairment		(73,133	)		(35,979	)
Property and equipment, net		630,097			673,432
Long-term derivative instruments		25			—
Restricted investments		156,848			156,938
Other long-term assets		5,998			8,545
Total assets	$	841,267		$	917,464

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	4,859		$	1,941
Revenues payable		24,269			22,427
Accrued liabilities (see Note 12)		20,345			18,233
Short-term derivative instruments		41,420			—
Total current liabilities		90,893			42,601
Long-term debt (see Note 8)		294,000			376,000
Asset retirement obligations		74,765			99,460
Long-term derivative instruments		10,030			5,470
Total liabilities		469,688			523,531
Commitments and contingencies (see Note 14)
Stockholders' equity:
Preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at September 30, 2018 and December 31, 2017, respectively		—			—
Warrants, 2,173,913 warrants issued and outstanding at September 30, 2018 and December 31, 2017		4,788			4,788
Common stock, $0.0001 par value: 300,000,000 shares authorized; 25,072,856 and 25,000,000 shares issued and outstanding at September 30, 2018 and December 31, 2017, respectively		3			3
Additional paid-in capital		390,140			387,856
Accumulated earnings (deficit)		(23,352	)		1,286
Total stockholders'/partners' equity		371,579			393,933
Total liabilities and equity	$	841,267		$	917,464

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

	Successor
	For the Three			For the Three
	Months Ended			Months Ended
	September 30, 2018			September 30, 2017
Revenues:
Oil and natural gas sales	$	85,446		$	75,534
Other revenues		76			55
Total revenues		85,522			75,589

Costs and expenses:
Lease operating expense		27,505			29,119
Gathering, processing and transportation		6,197			7,077
Exploration		9			4
Taxes other than income		4,717			4,214
Depreciation, depletion and amortization		13,355			13,467
General and administrative expense		8,219			11,097
Accretion of asset retirement obligations		1,272			1,665
(Gain) loss on commodity derivative instruments		21,110			14,217
(Gain) loss on sale of properties		(707	)		—
Other, net		639			772
Total costs and expenses		82,316			81,632
Operating income (loss)		3,206			(6,043	)
Other income (expense):
Interest expense, net		(5,336	)		(5,808	)
Other income (expense)		(2	)		—
Total other income (expense)		(5,338	)		(5,808	)
Income (loss) before reorganization items, net and income taxes		(2,132	)		(11,851	)
Reorganization items, net		(466	)		(33	)
Income tax benefit (expense)		—			4,348
Net income (loss)		(2,598	)		(7,536	)
Net income (loss) attributable to common stockholders/limited partners	$	(2,598	)	$	(7,536	)


Earnings per share: (See Note 10)
Basic and diluted earnings per share	$	(0.10	)	$	(0.30	)
Weighted average common shares outstanding:
Basic and diluted		25,073			25,000

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

	Successor						Predecessor
				Period from			Period from
	For the Nine			May 5, 2017			January 1,
	Months Ended			through			2017 through
	September 30, 2018			September 30, 2017			May 4, 2017
Revenues:
Oil and natural gas sales	$	264,187		$	117,762		$	108,970
Other revenues		255			222			231
Total revenues		264,442			117,984			109,201

Costs and expenses:
Lease operating expense		84,575			47,961			35,568
Gathering, processing, and transportation		17,772			11,191			10,772
Exploration		3,031			11			21
Taxes other than income		15,289			6,147			5,187
Depreciation, depletion, and amortization		39,932			21,818			37,717
General and administrative expense		35,739			18,479			31,606
Accretion of asset retirement obligations		4,419			2,692			3,407
(Gain) loss on commodity derivative instruments		67,218			12,302			(23,076	)
(Gain) loss on sale of properties		1,439			—			—
Other, net		519			772			36
Total costs and expenses		269,933			121,373			101,238
Operating income (loss)		(5,491	)		(3,389	)		7,963
Other income (expense):
Interest expense, net		(17,395	)		(9,605	)		(10,243	)
Other income (expense)		—			(6	)		8
Total other income (expense)		(17,395	)		(9,611	)		(10,235	)
Income (loss) before reorganization items, net and income taxes		(22,886	)		(13,000	)		(2,272	)
Reorganization items, net		(1,752	)		(382	)		(88,774	)
Income tax benefit (expense)		—			4,940			91
Net income (loss)		(24,638	)		(8,442	)		(90,955	)
Net income (loss) attributable to Successor/Predecessor	$	(24,638	)	$	(8,442	)	$	(90,955	)


Earnings per share/unit: (See Note 10)
Basic and diluted earnings per share/unit	$	(0.98	)	$	(0.34	)	$	(1.09	)
Weighted average common shares/units outstanding:
Basic and diluted		25,037			25,000			83,807

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

	Successor						Predecessor
				Period from			Period from
	For the Nine			May 5, 2017			January 1, 2017
	Months Ended			through			through
	September 30, 2018			September 30, 2017*			May 4, 2017*
Cash flows from operating activities:
Net income (loss)	$	(24,638	)	$	(8,442	)	$	(90,955	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		39,932			21,818			37,717
(Gain) loss on derivative instruments		67,218			12,302			(23,076	)
Cash settlements (paid) received on expired derivative instruments		6,287			21,277			15,895
Cash settlements (paid) on terminated derivatives		—			—			94,146
Deferred income tax expense (benefit)		—			(5,837	)		(74	)
Amortization and write-off of deferred financing costs		2,249			916			—
Accretion of asset retirement obligations		4,419			2,692			3,407
(Gain) loss on sale of properties		1,439			—			—
Share/unit-based compensation (see Note 11)		3,090			1,543			3,667
Settlement of asset retirement obligations		(600	)		(174	)		(164	)
Reorganization items, net		—			—			68,356
Other		—			—			56
Changes in operating assets and liabilities:
Accounts receivable		7,252			1,182			1,024
Prepaid expenses and other assets		1,698			5,683			735
Payables and accrued liabilities		8,279			(2,570	)		15,030
Other		(15	)		(77	)		(266	)
Net cash provided by operating activities		116,610			50,313			125,498
Cash flows from investing activities:
Additions to oil and gas properties		(46,002	)		(27,661	)		(6,211	)
Additions to other property and equipment		(167	)		(48	)		(76	)
Additions to restricted investments		(413	)		(310	)		(209	)
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold		18,088			—			—
Other		503			—			—
Net cash (used in) investing activities		(27,991	)		(28,019	)		(6,496	)
Cash flows from financing activities:
Advances on revolving credit facilities		21,000			—			16,600
Payments on revolving credit facilities		(103,000	)		(27,000	)		(98,252	)
Deferred financing costs		(18	)		(184	)		(8,575	)
Payment to holders of the Notes		—			(8,193	)		(16,446	)
Payment to Predecessor common unitholders		—			(1,250	)		—
Contribution from management		—			1,500			—
Restricted units returned to plan		(815	)		—			(10	)
Other		9			(9	)		9
Net cash (used in) provided by financing activities		(82,824	)		(35,136	)		(106,674	)
Net change in cash, cash equivalents and restricted cash		5,795			(12,842	)		12,328
Cash, cash equivalents and restricted cash, beginning of period		6,392			20,140			15,373
Cash, cash equivalents and restricted cash, end of period	$	12,187		$	7,298		$	27,701

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

	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)		—		—		—			(24,638	)		(24,638	)
Share-based compensation expense		—		—		3,090			—			3,090
Restricted shares repurchased		—		—		(815	)		—			(815	)
Other		—		—		9			—			9
Balance at September 30, 2018 (Successor)	$	3	$	4,788	$	390,140		$	(23,352	)	$	371,579

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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 in federal waters offshore 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.

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.

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

On May 1, 2018, the Company announced the retirement of William J. Scarff, the Company’s President and Chief Executive Officer and member of the board of directors, which retirement became effective May 14, 2018. 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 May 4, 2018, the board of directors appointed Kenneth Mariani to serve as President and Chief Executive Officer of the Company, effective May 14, 2018.

On May 17, 2018, Mr. Scarff resigned from the board of directors of the Company. There were no disagreements between Mr. Scarff and the Company which led to Mr. Scarff’s resignation from the board of directors. Also on May 17, 2018, the board of directors appointed Mr. Mariani to serve as a director of the Company to fill the vacancy caused by Mr. Scarff’s resignation.

On July 25, 2018, the board of directors appointed Denise DuBard to serve as Vice President and Chief Accounting Officer of the Company, effective August 9, 2018.

Also on July 25, 2018, Matthew J. Hoss tendered his resignation from his position as Vice President and Chief Accounting Officer of the Company, effective August 9, 2018. There were no disagreements between Mr. Hoss and the Company which led to his separation from the Company.

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, 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.

The Company adopted the new accounting pronouncement related to the presentation of statement of cash flows — restricted cash in the first quarter of 2018. See Note 2 for additional information. A retrospective change for the period from January 1, 2017 through May 4, 2017 and May 5, 2017 through September 30, 2017 on the Unaudited Condensed Statement of Consolidated Cash Flows as previously presented was required due to adoption. The table below sets forth the retrospective adjustments for the periods presented:

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.

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.

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

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
										Period from			Period from
	For the Three			For the Three			For the Nine			May 5, 2017			January 1,
	Months Ended			Months Ended			Months Ended			through			2017 through
	September 30, 2018			September 30, 2017			September 30, 2018			September 30, 2017			May 4, 2017
Gain on settlement of liabilities subject to compromise	$	—		$	—		$	—		$	—		$	758,764
Fresh start valuation adjustments		—			—			—			—			(827,120	)
Professional fees		(14	)		—			(638	)		(349	)		(19,824	)
Other		(452	)		(33	)		(1,114	)		(33	)		(594	)
Reorganization items, net	$	(466	)	$	(33	)	$	(1,752	)	$	(382	)	$	(88,774	)

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.

Fair Value Measurement. In August 2018, the FASB issued an amendment to modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement. Certain disclosure requirements were removed, modified and added and primarily relate to Level 3 hierarchy measurements and changes to non-public entities disclosures. The guidance is effective for all entities for fiscal years and interim periods within those fiscal years, beginning after December 15, 2019. The impact of this guidance is not expected to have a material impact on the Company.

Compensation—Stock Compensation. In May 2017, the FASB issued an accounting standards update to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance in the terms and conditions of a share-based payment award. The new guidance is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures.

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. We adopted this guidance and applied the disclosure requirements retrospectively to the Unaudited Condensed Statement of Consolidated Cash Flows.

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.

In July 2018, the FASB issued a revision to lease accounting implementation guidance, targeting improvements to comparative reporting requirements for initial adoption. Previously, the reporting requirements for initial adoption required an entity to initially apply the new leases standard (subject to specific transition requirements and optional practical expedients) at the beginning of the earliest period presented in the financial statements (which is January 1, 2017, for calendar-year-end public business entities that adopt the new leases standard on January 1, 2019). Under this new revision an optional method in addition to the existing method allows entities to initially apply the new leases standard at the adoption date January 1, 2019 for calendar-year-end public business entities and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. This option will be evaluated as part of the Company’s implementation process. The FASB also issued another update in July on additional codification improvements, primarily corrections and clarifications.

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.

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:

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 September 30, 2018.

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.

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 $27.9 million at September 30, 2018 and $30.1 million at December 31, 2017.

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.

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):

There were no material acquisitions during the three or nine months ended September 30, 2018.

On May 30, 2018, we closed a transaction to divest certain of our non-core assets located in South Texas (the “South Texas Divestiture”) for total proceeds of approximately $18.1 million, including estimated post-closing adjustments, which includes $18.6 million in cash and $0.5 million in accounts payable. We recorded a (gain) loss on sale of properties of approximately ($0.7) million and $1.4 million during the three and nine months ended September 30, 2018, respectively, in “(gain) loss on sale of properties” in the accompanying Unaudited Condensed Statements of Consolidated Operations. The net proceeds from the sale were used to reduce outstanding borrowings under our Credit Facility (as defined below). This disposition did not qualify as a discontinued operation.

There were no material acquisitions or divestitures for the three months ended September 30, 2017, the period from January 1, 2017 through May 4, 2017 or for the period from May 5, 2017 through September 30, 2017.

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 September 30, 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.

The fair market values of the derivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 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 September 30, 2018 and December 31, 2017 for each of the fair value hierarchy levels:

	Successor
	Fair Value Measurements at September 30, 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	$	—	$	6,508	$	—	$	6,508

Liabilities:
Commodity derivatives	$	—	$	56,937	$	—	$	56,937

	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

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:

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.

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 previous and current credit agreements 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 September 30, 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 $1.0 million against amounts outstanding under our Credit Facility (as defined below) at September 30, 2018. See Note 8 for additional information regarding our Credit Facility and our New Revolving Credit Facility (as defined below).

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 September 30, 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

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 September 30, 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 the Credit Agreement.

		Successor						Successor
		Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
		September 30,			September 30,			December 31,			December 31,
Type	Balance Sheet Location	2018			2018			2017			2017
		(In thousands)
Commodity contracts		$	6,220		$	46,644		$	37,729		$	9,183
Gross fair value			6,220			46,644			37,729			9,183
Netting arrangements			(5,224	)		(5,224	)		(9,183	)		(9,183	)
Net recorded fair value	Short-term derivative instruments	$	996		$	41,420		$	28,546		$	—

Commodity contracts		$	287		$	10,292		$	459		$	5,929
Gross fair value			287			10,292			459			5,929
Netting arrangements			(262	)		(262	)		(459	)		(459	)
Net recorded fair value	Long-term derivative instruments	$	25		$	10,030		$	—		$	5,470

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):

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 nine months ended September 30, 2018 (in thousands):

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

At September 30, 2018, Amplify Energy Operating LLC, our wholly owned subsidiary (“OLLC”), was a party to a $1.0 billion revolving credit facility (our “Credit Facility”) which was guaranteed by us and all of our current subsidiaries.

Our borrowing base under our Credit Facility was 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 took into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts.

On May 15, 2018, we entered into the Second Amendment to the Amended and Restated Credit Agreement, dated as of May 4, 2017 (the “Credit Agreement”), to among other things, (i) reflect the reduction of the borrowing base under the Credit Agreement from $435.0 million to $430.0 million, effective as of May 15, 2018, with the borrowing base to be further reduced by $15.0 million upon the consummation of the South Texas Divestiture and by $5.0 million each month until the next scheduled redetermination of the borrowing base; and (ii) amend the minimum hedging requirement to disregard the reasonably anticipated production of hydrocarbons from the assets to be sold in the South Texas Divestiture.

The borrowing base under our Credit Facility as of September 30, 2018 was $390.0 million.

On November 2, 2018, in connection with entry into the New Revolving Credit Facility (as defined below), the Credit Facility was terminated and repaid in full, as discussed below under “Subsequent Event—New Revolving Credit Facility.”

On November 2, 2018, OLLC and Amplify Acquisitionco, Inc., our wholly owned subsidiaries, entered into a credit agreement (the “New Credit Agreement”) providing for a new $425.0 million reserve-based revolving credit facility (the “New Revolving Credit Facility”) with Bank of Montreal, as administrative agent (in such capacity, the “Agent”) and an issuer of letters of credit, and the other lenders and agents from time to time party thereto. The New Revolving Credit Facility matures on November 2, 2023.

The New Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the PV-9 attributable to our oil and gas properties. The initial borrowing base is $425.0 million. The first scheduled redetermination will take place on or about April 1, 2019. The borrowing base will be redetermined semiannually on or around April 1st and October 1st, with one interim “wildcard” redetermination available between scheduled redeterminations. The April 1st scheduled redetermination will be based on a January 1st engineering report and the October 1st scheduled redetermination will be based on a July 1st engineering report. The January 1st engineering report will be audited by (or, at the option of OLLC, prepared by) an independent petroleum engineering firm reasonably acceptable to the Agent and the July 1st engineering report may be prepared internally by petroleum engineers who are employees of OLLC or its subsidiaries.

At OLLC’s option, borrowings under the New Credit Agreement will bear interest at the base rate, LIBOR Market Index rate or LIBOR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the federal funds effective rate plus 50 basis points, (ii) the rate of interest in effect for each day as publicly announced from time to time by the Agent as its “prime rate”; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points per annum. The applicable margin for base rate loans ranges from 100 to 200 basis points, and the applicable margin for LIBOR loans and LIBOR Market loans ranges from 200 to 300 basis points, in each case depending on the percentage of the borrowing base utilized.

The New Credit Agreement contains negative covenants that limit our and our subsidiaries’ ability, among other things, to pay dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of our business or operations, merge, consolidate, or make certain types of investments. In addition, the credit agreement requires that OLLC comply with the following financial covenants: (i) as of the date of determination, the ratio of total debt to EBITDAX (as defined in the New Credit Agreement) shall be no more than 4.00 to 1.00, and (ii) the current ratio (defined as consolidated current assets including unused amounts of the total commitments, but excluding non-cash assets under FASB ASC 815, divided by consolidated current liabilities excluding current non-cash obligations under FASB ASC 815 and current maturities under the New Credit Agreement) shall not be less than 1.00 to 1.00.

OLLC’s obligations under the New Credit Agreement may be accelerated, subject to customary grace and cure periods, upon the occurrence of certain Events of Default (as defined in the New Credit Agreement). Such Events of Default include customary events of default for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of our subsidiaries, defaults related to judgments and the occurrence of a Change in Control (as defined in the New Credit Agreement).

The Company’s obligations under the New Revolving Credit Facility are secured by mortgages on not less than 85% of the PV-9 value of oil and gas properties (and at least 85% of the PV-9 value of the proved, developed and producing oil and gas properties) included in the determination of the borrowing base. OLLC and our other subsidiaries entered into a Pledge and Security Agreement in favor of the Agent for the secured parties, pursuant to which OLLC’s obligations under the New Credit Agreement are secured by a first priority security interest in substantially all of our assets (subject to permitted liens). Additionally, the Company entered into a Non-Recourse Pledge Agreement in favor of the Agent for the secured parties, pursuant to which OLLC’s obligations under the New Credit Agreement are secured by a pledge and security interest of 100% of the equity interests held by the Company in Amplify Acquisitionco, Inc.

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.

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

At September 30, 2018, we had $2.4 million of letters of credit outstanding, primarily related to operations at our Wyoming properties.

Unamortized deferred financing costs associated with our Credit Facility was $4.9 million at September 30, 2018. At September 30, 2018, the unamortized deferred financing costs were amortized over the remaining life of our Credit Facility.

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 nine months ended September 30, 2018:

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.

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
										Period from			Period from
	For the Three			For the Three			For the Nine			May 5, 2017			January 1,
	Months Ended			Months Ended			Months Ended			through			2017 through
	September 30, 2018			September 30, 2017			September 30, 2018			September 30, 2017			May 4, 2017
Net income (loss) attributable to Successor/Predecessor	$	(2,598	)	$	(7,536	)	$	(24,638	)	$	(8,442	)	$	(90,955	)
Less: Net income allocated to participating restricted stockholders		—			—			—			—			—
Basic and diluted earnings available to common stockholders/limited partners	$	(2,598	)	$	(7,536	)	$	(24,638	)	$	(8,442	)	$	(90,955	)

Common shares/units:
Common shares/units outstanding — basic		25,073			25,000			25,037			25,000			83,807
Dilutive effect of potential common shares/units		—			—			—			—			—
Common shares/units outstanding — diluted		25,073			25,000			25,037			25,000			83,807

Net earnings per share/unit:
Basic	$	(0.10	)	$	(0.30	)	$	(0.98	)	$	(0.34	)	$	(1.09	)
Diluted	$	(0.10	)	$	(0.30	)	$	(0.98	)	$	(0.34	)	$	(1.09	)
Antidilutive stock options (1)		116			517			116			517			—
Antidilutive warrants (2)		2,174			2,174			2,174			2,174			—

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 restricted stock units with service vesting conditions (“TSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with the TSUs was $4.7 million at September 30, 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 TSUs granted under the MIP for the period presented:

The restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. As such, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost related to the PSUs was $1.1 million at September 30, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.4 years.

During the nine months ended September 30, 2018, the board of directors granted PSUs to certain executives of the Company. The PSUs will vest based on the satisfaction of service and market vesting conditions with market vesting based on the Company’s achievement of certain share price targets. The PSUs are subject to service-based vesting such that 50% of the PSUs service vest on the applicable market vesting date and an additional 25% of the PSUs service vest on each of the first and second anniversaries of the applicable market vesting date.

In the event of a qualifying termination, subject to certain conditions, (i) all PSUs that have satisfied the market vesting conditions will fully service vest, upon such termination, and (ii) if the termination occurs between the second and third anniversaries of the grant date, then PSUs that have not market vested as of the termination will market vest to the extent that the share targets (in each case, reduced by $0.25) are achieved as of such termination. Subject to the foregoing, any unvested PSUs will be forfeited upon termination of employment.

A Monte Carlo simulation was used in order to determine the fair value of these awards at the grant date.

Share price targets	$	12.50		$	15.00		$	17.50

Risk-free interest rate:
Awards Issued on May 14, 2018		2.68	%		2.68	%		2.68	%
Awards Issued on July 1, 2018		2.61	%		2.61	%		2.61	%
Awards Issued on August 1, 2018		2.76	%		2.76	%		2.76	%

Dividend yield		—			—			—

Expected volatility:
Awards Issued on May 14, 2018		50.0	%		50.0	%		50.0	%
Awards Issued on July 1, 2018		50.0	%		50.0	%		50.0	%
Awards Issued on August 1, 2018		55.0	%		55.0	%		55.0	%

Calculated fair value per PSU:
Awards Issued on May 14, 2018	$	9.71		$	8.52		$	7.48
Awards Issued on July 1, 2018	$	9.87		$	8.72		$	7.68
Awards Issued on August 1, 2018	$	9.79		$	8.66		$	7.65

The following table summarizes information regarding the PSUs granted under the MIP for the period presented:

The restricted stock options granted are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock option awards was $0.5 million at September 30, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.6 years.

No restricted stock options were granted during the three or nine months ended September 30, 2018.

The following table summarizes information regarding the restricted stock option awards granted under the MIP for the period presented:

On April 27, 2018, in connection with the separation and retirement of certain executives as discussed in Note 1, the board of directors of the Company approved the acceleration of the vesting schedule for 298,354 unvested restricted stock option awards with an exercisable period of two years that otherwise would have been forfeited upon an involuntary termination.

The acceleration of the restricted stock options vesting schedule represents an improbable to probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of $0.3 million was recognized.

The modified-date grant fair value was estimated using the Black-Scholes option pricing model using the following assumptions:

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 with a service vesting condition (“Board RSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock unit awards was $0.4 million at September 30, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.3 years.

The following table summarizes information regarding the Board RSUs granted under the Directors Compensation Plan for the period presented:

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

	Successor								Predecessor
							Period from		Period from
	For the Three		For the Three		For the Nine		May 5, 2017		January 1, 2017
	Months Ended		Months Ended		Months Ended		through		through
	September 30, 2018		September 30, 2017		September 30, 2018		September 30, 2017		May 4, 2017
Equity classified awards
TSUs (Successor)	$	490	$	745	$	601	$	1,168	$	—
PSUs (Successor)		495		—		747		—		—
Board RSUs (Successor)		44		19		98		22		—
Restricted stock options (Successor)		39		252		115		353		—
Restricted common units (Predecessor)		—		—		—		—		3,713
Liability classified awards
Phantom units (Predecessor)		—		—		—		—		(46	)
	$	1,068	$	1,016	$	1,561	$	1,543	$	3,667

Note 12. Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

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

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):

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 or nine months ended September 30, 2018, for the period from January 1, 2017 through May 4, 2017, or the period from May 5, 2017 through September 30, 2017.

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 was required to bring all outstanding issues to closure no later than June 30, 2018. On June 14, 2018, we sent the EPA a letter informing the EPA that we had completed all remedial action items related to the Administrative Compliance Order on Consent. In September 2018, we came to an agreement regarding the potential violations, noting no 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.

At September 30, 2018 and December 31, 2017, we had no environmental reserves recorded on our Unaudited Condensed Consolidated Balance Sheet.

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, (collectively, the “Closing Debtors”). On May 30, 2018, the court entered the final decree closing the chapter 11 cases of the Closing Debtors.

Beta Operating Company, LLC (“Beta”), has an obligation with the BOEM in connection with its 2009 acquisition of our properties in federal waters offshore California. The trust account (the “Beta Decommissioning Trust Account”) had the required minimum balance of $152.0 million at September 30, 2018 and December 31, 2017 and was fully cash funded. The held-to-maturity investments held in the Beta Decommissioning Trust Account at September 30, 2018 for the U.S. Bank money market cash equivalent was $152.5 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 2019 or later.

Subsequent Event. On October 5, 2018, the Company received approximately $61.5 million from the Beta Decommissioning Trust Account. The cash released to the Company’s balance sheet was made pursuant to an order of the U.S. Bankruptcy Court dated February 9, 2018, which allowed for the release of Beta cash subject to certain conditions that have since been satisfied. Following the cash release, Beta’s decommissioning obligations remain fully supported by A-rated surety bonds and $90.0 million of cash.

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 had no income tax benefit/(expense) for the three and nine months ended September 30, 2018, an income tax benefit of $4.3 million for the three months ended September 30, 2017; an income tax benefit of $4.9 million for the period from May 5, 2017 through September 30, 2017 and an income tax benefit of $0.1 million for the period from January 1, 2017 through May 4, 2017. The Company’s effective tax rate was 0.0% for the three and nine months ended September 30, 2018, 35.6% for the three months ended September 30, 2017, 36.1% for the period from May 5, 2017 through September 30, 2017 and 0.1% for the period from January 1, 2017 through May 4, 2017. The effective tax rates for the three and nine months ended September 30, 2018 are 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 September 30, 2017 and the period from May 5, 2017 through September 30, 2017 is different from the statutory U.S. federal income tax rate due to the impact of state taxes, disallowed expenses, and changes in the rate applied to historic deferred balances.

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 September 30, 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.

See Note 14 for additional information relating to the Beta Decommissioning Trust Account.

See Note 8 for additional information relating to our entrance into the New Revolving Credit Facility and, in connection therewith, the termination and repayment of our Credit Facility.

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.

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.

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 in federal waters offshore 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:

In October 2018, the Company received approximately $61.5 million from the Beta Decommissioning Trust Account. The cash released to the Company’s balance sheet was made pursuant to an order of the U.S. Bankruptcy Court dated February 9, 2018, which allowed for the release of Beta cash subject to certain conditions that have since been satisfied. Following the cash release, Beta’s decommissioning obligations remain still fully supported by A-rated surety bonds and $90 million of cash.

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.

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).

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.

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.

The results of operations for the three and nine months ended September 30, 2018, the three months ended September 30, 2017, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017 have been derived from our consolidated financial statements.

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

	Successor
	For the Three			For the Three
	Months Ended			Months Ended
	September 30, 2018			September 30, 2017
	($ In thousands)
Oil and natural gas sales	$	85,446		$	75,534
Lease operating expense		27,505			29,119
Gathering, processing and transportation		6,197			7,077
Exploration expense		9			4
Taxes other than income		4,717			4,214
Depreciation, depletion and amortization		13,355			13,467
General and administrative expense		8,219			11,097
Accretion of asset retirement obligations		1,272			1,665
(Gain) loss on commodity derivative instruments		21,110			14,217
(Gain) loss on sale of properties		(707	)		—
Interest expense, net		(5,336	)		(5,808	)
Reorganization items, net		(466	)		(33	)
Income tax benefit (expense)		—			4,348
Net income (loss)		(2,598	)		(7,536	)

Oil and natural gas revenue:
Oil sales	$	52,576		$	40,750
NGL sales		12,132			9,927
Natural gas sales		20,738			24,857
Total oil and natural gas revenue	$	85,446		$	75,534

Production volumes:
Oil (MBbls)		784			923
NGLs (MBbls)		364			437
Natural gas (MMcf)		7,134			8,158
Total (MMcfe)		14,024			16,317
Average net production (MMcfe/d)		152.4			177.4

Average sales price:
Oil (per Bbl)	$	67.03		$	44.16
NGL (per Bbl)		33.34			22.72
Natural gas (per Mcf)		2.91			3.05
Total (per Mcfe)	$	6.09		$	4.63

Average unit costs per Mcfe:
Lease operating expense	$	1.96		$	1.78
Gathering, processing and transportation		0.44			0.43
Taxes other than income		0.34			0.26
General and administrative expense		0.59			0.68
Depletion, depreciation and amortization		0.95			0.83

	Successor						Predecessor
				Period from			Period from
	For the Nine			May 5, 2017			January 1, 2017
	Months Ended			through			through
	September 30, 2018			September 30, 2017			May 4, 2017
	($ In thousands)						($ In thousands)
Oil and natural gas sales	$	264,187		$	117,762		$	108,970
Lease operating expense		84,575			47,961			35,568
Gathering, processing and transportation		17,772			11,191			10,772
Exploration expense		3,031			11			21
Taxes other than income		15,289			6,147			5,187
Depreciation, depletion and amortization		39,932			21,818			37,717
General and administrative expense		35,739			18,479			31,606
Accretion of asset retirement obligations		4,419			2,692			3,407
(Gain) loss on commodity derivative instruments		67,218			12,302			(23,076	)
(Gain) loss on sale of properties		1,439			—			—
Interest expense, net		(17,395	)		(9,605	)		(10,243	)
Reorganization items, net		(1,752	)		(382	)		(88,774	)
Income tax benefit (expense)		—			4,940			91
Net income (loss)		(24,638	)		(8,442	)		(90,955	)

Oil and natural gas revenue:
Oil sales	$	165,843		$	62,820		$	55,767
NGL sales		34,009			14,039			14,103
Natural gas sales		64,335			40,903			39,100
Total oil and natural gas revenue	$	264,187		$	117,762		$	108,970

Production volumes:
Oil (MBbls)		2,579			1,450			1,204
NGLs (MBbls)		1,167			658			616
Natural gas (MMcf)		22,575			13,250			12,411
Total (MMcfe)		45,053			25,893			23,336
Average net production (MMcfe/d)		165.0			173.8			188.2

Average sales price:
Oil (per Bbl)	$	64.30		$	43.35		$	46.28
NGL (per Bbl)		29.14			21.34			22.90
Natural gas (per Mcf)		2.85			3.09			3.15
Total (per Mcfe)	$	5.86		$	4.55		$	4.67

Average unit costs per Mcfe:
Lease operating expense	$	1.88		$	1.85		$	1.52
Gathering, processing and transportation		0.39			0.43			0.46
Taxes other than income		0.34			0.24			0.22
General and administrative expense		0.79			0.71			1.35
Depletion, depreciation and amortization		0.89			0.84			1.62

For the three months ended September 30, 2018 and the three months ended September 30, 2017

Net losses of $2.6 million and $7.5 million were recorded for the three months ended September 30, 2018 and 2017, respectively.

Oil, natural gas and NGL revenues were $85.4 million and $75.5 million for the three months ended September 30, 2018 and 2017, respectively. Average net production volumes were approximately 152.4 MMcfe/d and 177.4 MMcfe/d for the three months ended September 30, 2018 and 2017, respectively. The change in production volumes was primarily due to the natural decline of wells, decreased drilling activity and the divestiture of certain of our non-core assets located in South Texas (the “South Texas Divestiture”). The average realized sales price was $6.09 per Mcfe and $4.63 per Mcfe for the three months ended September 30, 2018 and 2017, respectively. The increase was primarily due to increases in realized prices for oil and NGLs.

Lease operating expense was $27.5 million and $29.1 million for the three months ended September 30, 2018 and 2017, respectively. The change in lease operating expense was primarily related to lower production. On a per Mcfe basis, lease operating expense was $1.96 and $1.78 for the three months ended September 30, 2018 and 2017, respectively.

Gathering, processing and transportation was $6.2 million and $7.1 million for the three months ended September 30, 2018 and 2017, respectively. The change in gathering, processing and transportation was primarily the 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 was $0.44 and $0.43 for each of the three months ended September 30, 2018 and 2017, respectively.

Taxes other than income was $4.7 million and $4.2 million for the three months ended September 30, 2018 and 2017, respectively. On a per Mcfe basis, taxes other than income were $0.34 and $0.26 for the three months ended September 30, 2018 and 2017, respectively. The change in taxes other than income on a per Mcfe basis was primarily due to an increase in commodity price.

DD&A expense was $13.4 million and $13.5 million for the three months ended September 30, 2018 and 2017, respectively. The change in DD&A expense was primarily due to a decrease in production volumes and the South Texas Divestiture, which closed on May 30, 2018 and which assets were accounted for as assets held for sale for the period from March 31, 2018 through the closing date.

General and administrative expense was $8.2 million and $11.1 million for the three months ended September 30, 2018 and 2017, respectively. Non-cash share-based compensation expense was $1.6 million and $1.0 million for the three months ended September 30, 2018 and 2017, respectively.

Net losses on commodity derivative instruments of $21.1 million were recognized for the three months ended September 30, 2018, consisting of $20.5 million decrease in the fair value of open positions and $0.6 million of cash settlements paid on expired positions. Net losses on commodity derivative instruments of $14.2 million were recognized for the three months ended September 30, 2017, consisting of a $27.2 million decrease in the fair value of open positions offset by $13.0 million of cash settlement receipts on expired 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 $5.3 million and $5.8 million for the three months ended September 30, 2018 and 2017, respectively. The Company recognized $0.5 million and $0.6 million in amortization and write-off of deferred financing costs for the three months ended September 30, 2018 and 2017, respectively.

Average outstanding borrowings under our Credit Facility were $306.7 million and $411.2 million for the three months ended September 30, 2018 and 2017, respectively.

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 the gain on settlement of liabilities subject to compromise, fresh start valuation adjustments, and advisor and professional fees. The Company incurred $0.5 million for the three months ended September 30, 2018 and less than $0.1 million for the three months ended September 30, 2017. See Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information.

For the nine months ended September 30, 2018, for the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017

Net losses of $24.6 million, $8.4 million and $91.0 million were recorded for the nine months ended September 30, 2018, for the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively.

Oil, natural gas and NGL revenues were $264.2 million, $117.8 million and $109.0 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. Average net production volumes were approximately 165.0 MMcfe/d, 173.8 MMcfe/d and 188.2 MMcfe/d for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The change in production volumes was due to natural decline of wells, decreased drilling activities and the South Texas Divestiture. The average realized sales price was $5.86 per Mcfe, $4.55 per Mcfe and $4.67 per Mcfe for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The change in the average realized sales price was primarily due to increases in realized prices for oil and NGLs.

Lease operating expense was $84.6 million, $48.0 million and $35.6 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. On a per Mcfe basis, lease operating expense was $1.88, $1.85 and $1.52 for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The change in lease operating expense on a per Mcfe basis was primarily related to lower production.

Gathering, processing and transportation expenses were $17.8 million, $11.2 million and $10.8 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The change in gathering, processing and transportation was primarily the 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 expenses were $0.39, $0.43 and $0.46 for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively.

Exploration expense was $3.0 million for the nine months ended September 30, 2018 and less than $0.1 million for the periods from May 5, 2017 through September 30, 2017 and from January 1, 2017 through May 4, 2017. The change in exploration expense was primarily due to a $2.9 million expense associated with the early termination of a rig contract in East Texas.

Taxes other than income was $15.3 million, $6.1 million and $5.2 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. On a per Mcfe basis, taxes other than income were $0.34, $0.24 and $0.22 for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The change in taxes other than income on a per Mcfe basis was primarily due to an increase in commodity prices.

DD&A expense was $39.9 million, $21.8 million and $37.7 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The change in DD&A expense was primarily due to lower rates as a result of the application of fresh start accounting, a decrease in production volumes and the South Texas Divestiture, which closed on May 30, 2018 and which assets were accounted for as held for sale for the period from March 31, 2018 through the closing date.

General and administrative expense was $35.7 million, $18.5 million and $31.6 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. General and administrative expense includes $7.5 million in severance payments to the Departing Executives during the nine months ended September 30, 2018. Non-cash share/unit-based compensation expense was $3.1 million, $1.5 million and $3.7 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The nine-month period ended September 30, 2018, includes a $1.7 million reduction in non-cash share/unit-based compensation expense related to the impact of management separation and retirement agreements for the Departing Executives, TSUs and restricted stock options. The period from January 1, 2017 through May 4, 2017 includes $2.3 million of non-cash share/unit-based compensation expense related to the cancellation of the Predecessor’s restricted common units. Additionally, the Company recorded $7.5 million in prepetition restructuring-related costs primarily for advisory and professional fees for the period from January 1, 2017 through May 4, 2017.

Net losses on commodity derivative instruments of $67.2 million were recognized for the nine months ended September 30, 2018, consisting of $6.3 million of cash settlements received on expired positions offset by a $73.5 million decrease in the fair value of open positions. Net losses on commodity derivative instruments of $12.3 million were recognized for the period from May 5, 2017 through September 30, 2017, consisting of $21.3 million of cash settlements receipts on expired positions which were offset by a $33.6 million decrease in the fair value of open positions. Net gains on commodity derivative instruments of $23.1 million were recognized for January 1, 2017 through May 4, 2017, consisting of $15.9 million of cash settlements receipts on expired positions and $94.1 million in cash settlements receipts on terminated derivatives. These receipts were partially offset by an $86.9 million decrease in the fair value of open positions.

Interest expense, net was $17.4 million, $9.6 million and $10.2 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The change in interest expense was primarily due to the Company not recording interest expense on the Predecessor’s 7.625% senior notes due May 2021 and 6.875% senior notes due August 2022 (collectively, the “Notes”) for the period from the Petition Date through the Effective Date. The Company recorded $3.5 million in interest expense for the Notes for the period from January 1, 2017 through May 4, 2017. No interest expense was recorded on the Notes for the period from May 5, 2017 through September 30, 2017, as the Notes were cancelled on the Effective Date. The Company recognized $2.2 million and $0.9 million in amortization and write-off of deferred financing cost for the nine months ended September 30, 2018 and the period from May 5, 2017 through September 30, 2017, respectively. No amortization of deferred financing cost was recorded for the period from January 1, 2017 through May 4, 2017, as the unamortized amount of deferred financing cost was written off in the fourth quarter of 2016.

Average outstanding borrowings under our Credit Facility were $334.8 million and $416.4 million for the nine months ended September 30, 2018 and for the period from May 5, 2017 through September 30, 2017, respectively. Average outstanding borrowings under the Predecessor’s revolving credit facility were $460.2 million for the period from January 1, 2017 through May 4, 2017. We had an average of $1.1 billion aggregate principal amount of the Notes issued and outstanding for the period from January 1, 2017 through May 4, 2017. The Notes were cancelled on the Effective Date.

Reorganization items, net represents costs and income directly associated with the Chapter 11 proceedings since January 16, 2017, the petition date, such as the gain on settlement of liabilities subject to compromise, fresh start valuation adjustments, advisors and professional fees. The Company incurred $1.8 million, $0.4 million and $88.8 million of reorganization items, net for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. See Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item1. Financial Statements” of this quarterly report for additional information.

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):

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.

	Successor												Predecessor
										Period from			Period from
	For the Three			For the Three			For the Nine			May 5, 2017			January 1,
	Months Ended			Months Ended			Months Ended			through			2017 through
	September 30, 2018			September 30, 2017			September 30, 2018			September 30, 2017			May 4, 2017
	(In thousands)												(In thousands)
Net income (loss)	$	(2,598	)	$	(7,536	)	$	(24,638	)	$	(8,442	)	$	(90,955	)
Interest expense, net		5,336			5,808			17,395			9,605			10,243
Income tax expense (benefit)		—			(4,348	)		—			(4,940	)		(91	)
DD&A		13,355			13,467			39,932			21,818			37,717
Accretion of AROs		1,272			1,665			4,419			2,692			3,407
(Gains) losses on commodity derivative instruments		21,110			14,217			67,218			12,302			(23,076	)
Cash settlements received (paid) on expired commodity derivative instruments		(616	)		12,992			6,287			21,276			15,895
(Gain) loss on sale of properties		(707	)		—			1,439			—			—
Acquisition and divestiture related expenses		82			238			969			238			—
Share/Unit-based compensation expense		1,578			1,016			3,090			1,543			3,667
Exploration costs		9			4			3,031			—			16
(Gain) loss on settlement of AROs		639			284			529			284			36
Restructuring related costs		—			—			—			—			7,548
Reorganization items, net		466			33			1,752			382			88,774
Severance payments		(258	)		—			7,451			—			—
Other		—			—			(105	)		—			57
Adjusted EBITDA	$	39,668		$	37,840		$	128,769		$	56,758		$	53,238

	Successor												Predecessor
										Period from			Period from
	For the Three			For the Three			For the Nine			May 5, 2017			January 1,
	Months Ended			Months Ended			Months Ended			through			2017 through
	September 30, 2018			September 30, 2017			September 30, 2018			September 30, 2017			May 4, 2017
	(In thousands)												(In thousands)
Net cash provided by (used in) operating activities	$	32,335		$	37,330		$	116,610		$	50,313		$	125,498
Changes in working capital		1,336			(6,358	)		(17,214	)		(4,219	)		(16,524	)
Interest expense, net		5,336			5,808			17,395			9,605			10,243
Cash settlements received on terminated derivatives		—			—			—			—			(94,146	)
Amortization of deferred financing fees		(497	)		(570	)		(2,249	)		(916	)		—
Acquisition and divestiture related expenses		82			238			969			238			—
Income tax expense (benefit) - current portion		—			897			—			897			(17	)
Exploration costs		9			4			3,031			—			16
Plugging and abandonment cost		859			458			1,129			458			200
Restructuring related costs		—			—			—			—			7,548
Reorganization items, net		466			33			1,752			382			20,420
Severance payments		(258	)		—			7,451			—			—
Other		—			—			(105	)		—			—
Adjusted EBITDA	$	39,668		$	37,840		$	128,769		$	56,758		$	53,238

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 and available borrowing capacity under our New Revolving Credit Facility.

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 50% 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 New Revolving 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 September 30, 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 $45.8 million for the nine months ended September 30, 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 federal waters offshore 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 2019 or later. At September 30, 2018, there was approximately $152.5 million in the trust account and $62.0 million in surety bonds. On October 5, 2018, the Company received approximately $61.5 million from the Beta Decommissioning Trust Account. The cash released to the Company’s balance sheet was made pursuant to an order of the U.S. Bankruptcy Court dated February 9, 2018, which allowed for the release of Beta cash subject to certain conditions that have since been satisfied. Following the cash release, Beta’s decommissioning obligations remain fully supported by A-rated surety bonds and $90.0 million of cash.

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. 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.

As of September 30, 2018, we had a working capital deficit of $42.6 million primarily due to accrued liabilities of $20.3 million, revenues payable of $24.3 million and a current derivative liability of $41.4 million, partially offset by an accounts receivable balance of $28.8 million and a cash balance of $11.9 million.

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. At September 30, 2018, our borrowing base under our Credit Facility was 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 took into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts.

On May 15, 2018, we entered into the Second Amendment to the Amended and Restated Credit Agreement, dated as of May 4, 2017, to among other things, (i) reflect the reduction of the borrowing base under the Credit Agreement from $435.0 million to $430.0 million, effective as of May 15, 2018, with the borrowing base to be further reduced by $15.0 million upon the consummation of the South Texas Divestiture and by $5.0 million each month until the next scheduled redetermination of the borrowing base; and (ii) amend the minimum hedging requirement to disregard the reasonably anticipated production of hydrocarbons from the assets to be sold in the South Texas Divestiture. The borrowing base as of September 30, 2018, was $390.0 million.

As of September 30, 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 September 30, 2018, we had approximately $93.6 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.

On November 2, 2018, in connection with entry into the New Revolving Credit Facility, the Credit Facility was terminated and repaid in full. For additional information regarding the New Revolving Credit Facility, see “— Recent Developments — New Revolving Credit Facility” and Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 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.

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $116.6 million, $50.3 and $125.5 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. Production volumes were approximately 165.0 MMcfe/d, 173.8 MMcfe/d and 188.2 MMcfe/d for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. The average realized sales price was $5.86 per Mcfe, $4.55 per Mcfe and $4.67 per Mcfe for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. Lease operating expenses were $84.6 million, $48.0 million and $35.6 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. Gathering, processing and transportation was $17.8 million, $11.2 million and $10.8 million for the nine months ended September 30, 2018, the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. Cash settlements received on terminated derivatives were $94.1 million for the period from January 1, 2017 through May 4, 2017.

Investing Activities. Net cash used in investing activities for the nine months ended September 30, 2018 was $28.0 million, of which $46.0 million was used for additions to oil and natural gas properties and partially offset by $18.1 million in proceeds from the sale of oil and natural gas properties primarily related to the South Texas Divestiture. Net cash used in investing activities for the period from May 5, 2017 through September 30, 2017 was $28.0 million, of which $27.7 million was used for additions to oil and natural gas properties. Net cash used in investing activities for the period from January 1, 2017 through May 4, 2017 was $6.5 million, of which $6.2 million was used for additions to oil and natural gas properties.

Financing Activities. The Company had net repayments of $82.0 million and $27.0 million under the Credit Facility for the nine months ended September 30, 2018 and for the period from May 5, 2017 through September 30, 2017, respectively. The Company made $8.2 million in payments to the holders of the Notes and $1.3 million in payments to the Predecessor common unitholders, and the Company received a $1.5 million contribution from management in accordance with the Plan for the period from May 5, 2017 through September 30, 2017. The Company had net repayments of $81.7 million under the Predecessor’s revolving credit facility for the period from January 1, 2017 through May 4, 2017. In addition, the Company had made $16.4 million in payments to the holders of the Notes in accordance with the Plan and paid $8.6 million in deferred financing costs for the period from January 1, 2017 through May 4, 2017.

During the nine months ended September 30, 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.

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.

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.

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 September 30, 2018, see Note 6 of the Notes to Unaudited Condensed Consolidated Financial Statements included “Item 1. Financial Statements” of this quarterly report.

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 our previous and current credit agreements 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 September 30, 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 $1.0 million against amounts outstanding under our Credit Facility at September 30, 2018.

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 September 30, 2018.

No changes in our internal control over financial reporting occurred during the quarter ended September 30, 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.

For information regarding legal proceedings, see Part I, “Item 1. Financial Statements,” Note 14, “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.

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.

The following table summarizes our repurchase activity during the three months ended September 30, 2018:

On November 2, 2018, Amplify Energy Operating LLC (“OLLC”) and Amplify Acquisitionco, Inc., wholly owned subsidiaries of the Company, entered into a credit agreement (the “New Credit Agreement”) providing for a new $425.0 million reserve-based revolving credit facility (the “New Revolving Credit Facility”) with Bank of Montreal, as administrative agent (in such capacity, the “Agent”) and an issuer of letters of credit, and the other lenders and agents from time to time party thereto. The New Revolving Credit Facility matures on November 2, 2023.

The foregoing description of the New Credit Agreement does not purport to be complete and is qualified in its entirety by reference to the New Credit Agreement, which is attached to this quarterly report as Exhibit 10.2 and is incorporated by reference herein.

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.

Delaware		82-1326219
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

500 Dallas Street, Suite 1700, Houston, TX		77002
(Address of principal executive offices)		(Zip Code)

Large accelerated filer ☐	Accelerated filer ☑
Non-accelerated filer ☐	Smaller reporting company ☐
Emerging growth company ☐

	Predecessor
	Previously Reported Period from January 1, 2017 through May 4, 2017			Adjustment Effect		As Adjusted Period from January 1, 2017 through May 4, 2017
	(In thousands)
Changes in operating assets and liabilities:
Restricted cash	$	(7,561	)	$	7,561	$	—
Net cash provided by operating activities		117,937			7,561		125,498
Net change in cash and cash equivalents		4,767			7,561		12,328
Cash and cash equivalents, end of period		20,140			7,561		27,701

	Successor
	Previously Reported Period from May 5, 2017 through September 30, 2017			Adjustment Effect			As Adjusted Period from May 5, 2017 through September 30, 2017
	(In thousands)
Changes in operating assets and liabilities:
Restricted cash	$	7,561		$	(7,561	)	$	—
Net cash provided by operating activities		57,874			(7,561	)		50,313
Net change in cash and cash equivalents		(5,281	)		(7,561	)		(12,842	)
Cash and cash equivalents, end of period		14,859			(7,561	)		7,298

Asset retirement obligations at beginning of period (Successor)	$	100,173
Liabilities added from acquisition or drilling		89
Liabilities settled		(600	)
Liabilities removed upon sale of wells		(15,665	)
Accretion expense		4,419
Revision of estimates (1)		(13,213	)
Asset retirement obligation at end of period		75,203
Less: Current portion		(438	)
Asset retirement obligations - long-term portion (Successor)	$	74,765

		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 September 30, 2018 (Successor Period) and December 31, 2017 (Successor Period)	7
	Unaudited Condensed Statements of Consolidated Operations for the Three and Nine Months Ended September 30, 2018 (Successor Period), the three months ended September 30, 2017 (Successor Period), the period from May 5, 2017 through September 30, 2017 (Successor Period) and the period from January 1, 2017 through May 4, 2017 (Predecessor Period)	8
	Unaudited Condensed Statements of Consolidated Cash Flows for the Nine Months Ended September 30, 2018 (Successor Period), the period from May 5, 2017 through September 30, 2017 (Successor Period) and the period from January 1, 2017 through May 4, 2017 (Predecessor Period)	10
	Unaudited Condensed Statements of Consolidated Equity for the Nine Months Ended September 30, 2018 (Successor Period)	11
	Notes to Unaudited Condensed Consolidated Financial Statements
	Note 1 – Organization and Basis of Presentation	12
	Note 2 – Summary of Significant Accounting Policies	14
	Note 3 – Revenue	15
	Note 4 – Acquisitions and Divestitures	17
	Note 5 – Fair Value Measurements of Financial Instruments	17
	Note 6 – Risk Management and Derivative Instruments	19
	Note 7 – Asset Retirement Obligations	20
	Note 8 – Long-term Debt	21
	Note 9 – Equity (Deficit)	23
	Note 10 – Earnings per Share/Unit	23
	Note 11 – Long-Term Incentive Plans	24
	Note 12 -Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Statements of Consolidated Cash Flows	27
	Note 13 – Related Party Transactions	28
	Note 14 – Commitments and Contingencies	28
	Note 15 – Income Taxes	29
	Note 16 – Subsequent Events	29

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	41

PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	43

Signatures		45

	For the Three Months Ended
	September 30, 2018
	As Reported			Previous Revenue Recognition Method			Increase/ (Decrease)
	(in thousands)
Revenues:
Oil and natural gas sales	$	85,446		$	86,173		$	(727	)
Cost and expenses:
Gathering, processing and transportation		6,197			6,923		$	(727	)

Net income (loss)	$	(2,598	)	$	(2,598	)	$	—

	For the Nine Months Ended
	September 30, 2018
	As Reported			Previous Revenue Recognition Method			Increase/ (Decrease)
	(in thousands)
Revenues:
Oil and natural gas sales	$	264,187		$	266,101		$	(1,914	)
Cost and expenses:
Gathering, processing and transportation		17,772			19,686		$	(1,914	)

Net income (loss)	$	(24,638	)	$	(24,638	)	$	—

	Common
	Shares
Balance, December 31, 2017 (Successor)		25,000,000
Issuance of common stock		—
Restricted stock units vested		129,737
Repurchase of common shares		(56,881	)
Balance, September 30, 2018 (Successor)		25,072,856

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
TSUs outstanding at December 31, 2017 (Successor)		682,792		$	13.54
Granted (2)		256,500		$	10.91
Forfeited (3)		(360,513	)	$	13.57
Vested		(124,292	)	$	13.77
TSUs outstanding at September 30, 2018 (Successor)		454,487		$	11.97

	Awards Issued in
	Successor Period
Risk-free interest rate		2.49	%
Dividend yield		—
Expected life (in years)		2.0
Expected volatility		50.0	%
Strike Price	$	21.58
Calculated fair value per stock option	$	0.85

	Successor					Predecessor
	For The			Period from		Period from
	Nine Months			May 5, 2017		January 1, 2017
	Ended			through		through
	September 30, 2018			September 30, 2017		May 4, 2017
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	15,405		$	7,039	$	6,598
Cash paid for reorganization items, net		2,004			7,333		11,999
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(565	)		12,636		3,173

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).

10.1*	—	Employment Agreement, dated July 30, 2018, by and between Amplify Energy Corp. and Denise DuBard.

10.2*	—	Credit Agreement, dated as of November 2, 2018, among Amplify Energy Operating LLC, Amplify Acquisitionco, Inc., as parent, Bank of Montreal, as administrative agent and an L/C issuer, and the other lenders and agents from time to time party thereto.

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

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

Exhibit Number		Description
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

	Amplify Energy Corp.
	(Registrant)


Date: November 7, 2018	By:	/s/ Martyn Willsher
	Name:	Martyn Willsher
	Title:	Senior Vice President and Chief Financial Officer


Date: November 7, 2018	By:	/s/ Denise DuBard
	Name:	Denise DuBard
	Title:	Vice President and Chief Accounting Officer