~~(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,~~May 3, 2019, the registrant had ~~25,072,856~~22,212,290 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.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

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.

Plugging and abandonment: Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface. Regulations of all states require plugging of abandoned wells.

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~~2018 filed with the SEC on March ~~12,~~ 6, 2019 (“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,			March 31,			December 31,
	2018			2017			2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	11,862		$	6,392		$	24,876		$	49,704
Restricted cash		325			—			325			325
Accounts receivable		28,833			36,391			25,086			29,514
Short-term derivative instruments		996			28,546			276			18,813
Prepaid expenses and other current assets		6,283			7,220			9,738			7,241
Total current assets		48,299			78,549			60,301			105,597
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		593,361			603,053			609,414			598,331
Support equipment and facilities		103,569			100,225			110,725			108,760
Other		6,300			6,133			6,687			6,625
Accumulated depreciation, depletion and impairment		(73,133	)		(35,979	)		(96,701	)		(85,535	)
Property and equipment, net		630,097			673,432			630,125			628,181
Long-term derivative instruments		25			—			288			2,469
Restricted investments		156,848			156,938			94,536			94,467
Operating lease - long term right-of-use asset								5,011			—
Other long-term assets		5,998			8,545			5,922			6,129
Total assets	$	841,267		$	917,464		$	796,183		$	836,843

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	4,859		$	1,941		$	4,580		$	2,345
Revenues payable		24,269			22,427			24,136			24,779
Accrued liabilities (see Note 12)		20,345			18,233
Accrued liabilities (see Note 13)								21,199			23,155
Short-term derivative instruments		41,420			—			9,108			139
Total current liabilities		90,893			42,601			59,023			50,418
Long-term debt (see Note 8)		294,000			376,000			270,000			294,000
Asset retirement obligations		74,765			99,460			77,082			75,867
Long-term derivative instruments		10,030			5,470			1,429			—
Operating lease liability								3,090			—
Other long-term liabilities								62			—
Total liabilities		469,688			523,531			410,686			420,285
Commitments and contingencies (see Note 14)
Commitments and contingencies (see Note 15)
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
Preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at March 31, 2019 and December 31, 2018, respectively								—			—
Warrants, 2,173,913 warrants issued and outstanding at March 31, 2019 and December 31, 2018, respectively								4,788			4,788
Common stock, $0.0001 par value: 300,000,000 shares authorized; 22,258,450 and 22,181,881 shares issued and outstanding at March 31, 2019 and December 31, 2018, respectively								3			3
Additional paid-in capital		390,140			387,856			356,288			355,872
Accumulated earnings (deficit)		(23,352	)		1,286			24,418			55,895
Total stockholders'/partners' equity		371,579			393,933
Total stockholders' equity								385,497			416,558
Total liabilities and equity	$	841,267		$	917,464		$	796,183		$	836,843

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

	Successor
	For the Three			For the Three			For the Three Months Ended
	Months Ended			Months Ended			March 31,
	September 30, 2018			September 30, 2017			2019			2018
Revenues:
Oil and natural gas sales	$	85,446		$	75,534		$	65,067		$	87,847
Other revenues		76			55			88			85
Total revenues		85,522			75,589			65,155			87,932

Costs and expenses:
Lease operating expense		27,505			29,119			28,910			29,570
Gathering, processing and transportation		6,197			7,077			4,657			5,600
Exploration		9			4			15			34
Taxes other than income		4,717			4,214			4,409			5,037
Depreciation, depletion and amortization		13,355			13,467			11,166			12,958
General and administrative expense		8,219			11,097			9,308			10,657
Accretion of asset retirement obligations		1,272			1,665			1,311			1,718
(Gain) loss on commodity derivative instruments		21,110			14,217			32,487			10,456
(Gain) loss on sale of properties		(707	)		—			—			2,373
Other, net		639			772			143			—
Total costs and expenses		82,316			81,632			92,406			78,403
Operating income (loss)		3,206			(6,043	)		(27,251	)		9,529
Other income (expense):
Interest expense, net		(5,336	)		(5,808	)		(4,089	)		(5,772	)
Other income (expense)		(2	)		—
Total other income (expense)		(5,338	)		(5,808	)		(4,089	)		(5,772	)
Income (loss) before reorganization items, net and income taxes		(2,132	)		(11,851	)		(31,340	)		3,757
Reorganization items, net		(466	)		(33	)		(187	)		(518	)
Income tax benefit (expense)		—			4,348			50			—
Net income (loss)		(2,598	)		(7,536	)		(31,477	)		3,239
Net income (loss) attributable to common stockholders/limited partners	$	(2,598	)	$	(7,536	)

Net (income) loss allocated to participating restricted stockholders								—			(83	)
Net income (loss) attributable to common stockholders							$	(31,477	)	$	3,156

Earnings per share: (See Note 10)
Basic and diluted earnings per share	$	(0.10	)	$	(0.30	)	$	(1.42	)	$	0.13
Weighted average common shares outstanding:
Basic and diluted		25,073			25,000			22,179			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			For the Three Months Ended
	Months Ended			through			through			March 31,
	September 30, 2018			September 30, 2017*			May 4, 2017*			2019			2018
Cash flows from operating activities:
Net income (loss)	$	(24,638	)	$	(8,442	)	$	(90,955	)	$	(31,477	)	$	3,239
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		39,932			21,818			37,717			11,166			12,958
(Gain) loss on derivative instruments		67,218			12,302			(23,076	)		32,393			10,456
Cash settlements (paid) received on expired derivative instruments		6,287			21,277			15,895			(1,277	)		4,876
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			—
Bad debt expense											101			—
Amortization of deferred financing costs											308			541
Accretion of asset retirement obligations		4,419			2,692			3,407			1,311			1,718
(Gain) loss on sale of properties		1,439			—			—			—			2,373
Share/unit-based compensation (see Note 11)		3,090			1,543			3,667
Share-based compensation (see Note 11)											1,443			1,176
Settlement of asset retirement obligations		(600	)		(174	)		(164	)		(162	)		—
Reorganization items, net		—			—			68,356
Other		—			—			56
Changes in operating assets and liabilities:
Accounts receivable		7,252			1,182			1,024			4,326			2,839
Prepaid expenses and other assets		1,698			5,683			735			(6,856	)		(115	)
Payables and accrued liabilities		8,279			(2,570	)		15,030			(537	)		2,086
Other		(15	)		(77	)		(266	)		61			—
Net cash provided by operating activities		116,610			50,313			125,498			10,800			42,147
Cash flows from investing activities:
Additions to oil and gas properties		(46,002	)		(27,661	)		(6,211	)		(10,370	)		(13,098	)
Additions to other property and equipment		(167	)		(48	)		(76	)		(62	)		—
Additions to restricted investments		(413	)		(310	)		(209	)		(68	)		(186	)
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	)
Net cash used in investing activities											(10,500	)		(13,284	)
Cash flows from financing activities:
Advances on revolving credit facilities		21,000			—			16,600			—			5,000
Payments on revolving credit facilities		(103,000	)		(27,000	)		(98,252	)		(24,000	)		(34,000	)
Deferred financing costs		(18	)		(184	)		(8,575	)		(101	)		—
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	)
Costs incurred in conjunction with tender offer											(107	)		—
Common stock repurchased and retired under the share repurchase program											(920	)		—
Other		9			(9	)		9			—			(213	)
Net cash (used in) provided by financing activities		(82,824	)		(35,136	)		(106,674	)
Net cash used in financing activities											(25,128	)		(29,213	)
Net change in cash, cash equivalents and restricted cash		5,795			(12,842	)		12,328			(24,828	)		(350	)
Cash, cash equivalents and restricted cash, beginning of period		6,392			20,140			15,373			50,029			6,392
Cash, cash equivalents and restricted cash, end of period	$	12,187		$	7,298		$	27,701		$	25,201		$	6,042

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													Stockholders' Equity
	Common Stock		Warrants		Additional Paid-in Capital			Accumulated Earnings (Deficit)			Total			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
Balance at December 31, 2017														$	3	$	4,788	$	387,856		$	1,286	$	393,933
Net income (loss)		—		—		—			(24,638	)		(24,638	)		—		—		—			3,239		3,239
Share-based compensation expense		—		—		3,090			—			3,090			—		—		1,176			—		1,176
Restricted shares repurchased		—		—		(815	)		—			(815	)
Other		—		—		9			—			9			—		—		(208	)		—		(208	)
Balance at September 30, 2018 (Successor)	$	3	$	4,788	$	390,140		$	(23,352	)	$	371,579
Balance at March 31, 2018														$	3	$	4,788	$	388,824		$	4,525	$	398,140

	Stockholders' Equity
	Common Stock		Warrants		Additional Paid-in Capital			Accumulated Earnings (Deficit)			Total
Balance at December 31, 2018	$	3	$	4,788	$	355,872		$	55,895		$	416,558
Net income (loss)		—		—		—			(31,477	)		(31,477	)
Costs incurred in conjunction with tender offer		—		—		(107	)		—			(107	)
Share-based compensation expense		—		—		1,443			—			1,443
Common stock repurchased and retired under the share repurchase program		—		—		(920	)		—			(920	)
Restricted shares repurchased		—		—		—			—			—
Other		—		—		—			—			—
Balance at March 31, 2019	$	3	$	4,788	$	356,288		$	24,418		$	385,497

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~~the Rockies, federal waters offshore ~~California.~~Southern California, East Texas / North Louisiana and South Texas. 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.

Beginning in 2019, the Company has elected to change its reporting convention from natural gas equivalent (Mcfe) to barrels of oil equivalent (Boe). The ~~Company adopted the new accounting pronouncement related to the~~change in 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~~reflects our liquids-weighted production 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 presentedreserve profile with a ~~“black line” division~~balanced approach to ~~delineate the lack~~development of ~~comparability between the Predecessor~~our oil and ~~Successor.~~natural gas asset portfolio. The Company’s proved reserves as of year-end 2018 were 50% crude oil, 15% natural gas liquids and 35% natural gas.

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~~2018 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 January 16, 2017, the ~~Petition Date.~~petition date.

The following table summarizes the components of reorganization items, net included in the accompanying Unaudited Condensed Statements of Consolidated Operations (in thousands):

	Successor												Predecessor			For the Three Months Ended
										Period from			Period from			March 31,
	For the Three			For the Three			For the Nine			May 5, 2017			January 1,			2019			2018
	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	)		(26	)		(414	)
Other		(452	)		(33	)		(1,114	)		(33	)		(594	)		(161	)		(104	)
Reorganization items, net	$	(466	)	$	(33	)	$	(1,752	)	$	(382	)	$	(88,774	)	$	(187	)	$	(518	)

In ~~May 2014,~~February 2016, the ~~Financial Accounting Standards Board (“FASB”)~~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.~~leases. 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, vehicles and surface rentals (right of use assets) 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~~applied the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using athe modified retrospective approach with a cumulative impact to retained earnings in that period, and including several optional practical expedients ~~related~~relating to leases commenced before the effective date. The practical expedients the Company ~~is currently evaluating~~adopted are: (1) the ~~impact~~original correct assessment of ~~these rules~~a contract containing a lease will be accepted without further review on ~~its financial statements and has started~~all existing or expired contracts; (2) the ~~assessment process by evaluating the population of leases~~original lease classification as an operating lease will convert as an operating lease under the ~~revised definition. The quantitative impacts~~new guidance; (3) initial direct costs for any existing leases will not be reassessed; (4) existing land easements or right of use agreements will continue under current accounting policy and only new agreements will be evaluated in the future; and (5) short-term leases for twelve months or less will not be evaluated under the guidance.

See Note 12 for additional information regarding the adoption 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.~~standard.

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~~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.~~March 31, 2019.

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

					For the Three Months Ended
	For the Three Months Ended		For the Nine Months Ended		March 31,
	September 30, 2018		September 30, 2018		2019		2018
	(in thousands)				(in thousands)
Revenues
Oil	$	52,576	$	165,843	$	40,057	$	54,726
NGLs		12,132		34,009	$	5,865	$	10,946
Natural gas		20,738		64,335	$	19,145	$	22,175
Oil and natural gas sales	$	85,446	$	264,187	$	65,067	$	87,847

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~~$24.8 million at ~~September 30, 2018~~March 31, 2019 and ~~$30.1~~$25.0 million at December 31, ~~2017.~~2018.

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 or divestitures during the three ~~or nine~~ months ended ~~September 30, 2018.~~March 31, 2019.

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~~$17.1 million, including ~~estimated~~final 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).adjustments. 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~~March 31, 2019 and December 31, ~~2017.~~2018. 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~~March 31, 2019 and December 31, ~~2017~~2018 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~~March 31, 2019 and December 31, ~~2017~~2018 for each of the fair value hierarchy levels:

	Successor
	Fair Value Measurements at September 30, 2018 Using								Fair Value Measurements at March 31, 2019 Using
	Quoted Prices in		Significant Other		Significant				Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs				Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value		(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)								(In thousands)
Assets:
Commodity derivatives	$	—	$	6,508	$	—	$	6,508	$	—	$	7,992	$	—	$	7,992
Interest rate derivatives										—		142		—		142
Total assets									$	—	$	8,134	$	—	$	8,134

Liabilities:
Commodity derivatives	$	—	$	56,937	$	—	$	56,937	$	—	$	18,058	$	—	$	18,058
Interest rate derivatives										—		49		—		49
Total liabilities									$	—	$	18,107	$	—	$	18,107

	Successor
	Fair Value Measurements at December 31, 2017 Using								Fair Value Measurements at December 31, 2018 Using
	Quoted Prices in		Significant Other		Significant				Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs				Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value		(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)								(In thousands)
Assets:
Commodity derivatives	$	—	$	38,188	$	—	$	38,188	$	—	$	25,515	$	—	$	25,515

Liabilities:
Commodity derivatives	$	—	$	15,112	$	—	$	15,112	$	—	$	4,372	$	—	$	4,372

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,~~March 31, 2019, 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~~$0.1 million against amounts outstanding under our New Revolving Credit Facility (as defined below) at ~~September 30, 2018.~~March 31, 2019. See Note 8 for additional information regarding our Emergence 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,~~March 31, 2019, we had the following open commodity positions:

	Remaining				Remaining
	2018		2019		2019		2020		2021
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (MMBtu)		1,802,000		1,250,000		1,540,000		150,000		—
Weighted-average fixed price	$	3.54	$	2.82	$	2.88	$	2.65	$	—

Collar contracts:
Average monthly volume (MMBtu)						—		520,000		87,500
Weighted-average floor price						—	$	2.64	$	2.66
Weighted-average ceiling price					$	—	$	2.96	$	2.99

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		205,000		186,000		135,333		75,000		33,750
Weighted-average fixed price	$	69.14	$	54.08	$	52.60	$	56.33	$	55.93

Collar contracts:
Average monthly volume (Bbls)						50,667		14,300		—
Weighted-average floor price					$	55.00	$	55.00	$	—
Weighted-average ceiling price					$	63.85	$	62.10	$	—

Purchased put option contracts:
Average Monthly Volume (Bbls)						—		25,550		—
Weighted-average strike price					$	—	$	55.00	$	—
Weighted-average deferred premium					$	—	$	7.09	$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		86,800		72,000		72,000		37,925		5,500
Weighted-average fixed price	$	25.85	$	29.96	$	29.96	$	27.94	$	27.23

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. At March 31, 2019, we had the following interest rate swap open positions:

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~~March 31, 2019 and December 31, ~~2017.~~2018. 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.~~our credit agreement.

		Successor						Successor
		Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives				Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
		September 30,			September 30,			December 31,			December 31,				March 31,			March 31,			December 31,			December 31,
Type	Balance Sheet Location	2018			2018			2017			2017			Balance Sheet Location	2019			2019			2018			2018
		(In thousands)													(In thousands)
Commodity contracts		$	6,220		$	46,644		$	37,729		$	9,183		Short-term derivative instruments	$	4,504		$	13,469		$	21,217		$	2,543
Interest rate swaps														Short-term derivative instruments		133			—			—			—
Gross fair value			6,220			46,644			37,729			9,183				4,637			13,469			21,217			2,543
Netting arrangements			(5,224	)		(5,224	)		(9,183	)		(9,183	)			(4,361	)		(4,361	)		(2,404	)		(2,404	)
Net recorded fair value	Short-term derivative instruments	$	996		$	41,420		$	28,546		$	—		Short-term derivative instruments	$	276		$	9,108		$	18,813		$	139

Commodity contracts		$	287		$	10,292		$	459		$	5,929		Long-term derivative instruments	$	3,489		$	4,590		$	4,298		$	1,829
Interest rate swaps														Long-term derivative instruments		9			49			—			—
Gross fair value			287			10,292			459			5,929				3,498			4,639			4,298			1,829
Netting arrangements			(262	)		(262	)		(459	)		(459	)			(3,210	)		(3,210	)		(1,829	)		(1,829	)
Net recorded fair value	Long-term derivative instruments	$	25		$	10,030		$	—		$	5,470		Long-term derivative instruments	$	288		$	1,429		$	2,469		$	—

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~~three months ended ~~September 30, 2018~~March 31, 2019 (in thousands):

Asset retirement obligations at beginning of period (Successor)	$	100,173
Asset retirement obligations at beginning of period				$	76,344
Liabilities added from acquisition or drilling		89			7
Liabilities settled		(600	)		(162	)
Liabilities removed upon sale of wells		(15,665	)
Accretion expense		4,419			1,311
Revision of estimates (1)		(13,213	)
Revision of estimates					59
Asset retirement obligation at end of period		75,203			77,559
Less: Current portion		(438	)		(477	)
Asset retirement obligations - long-term portion (Successor)	$	74,765
Asset retirement obligations - long-term portion				$	77,082

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

	Successor		Successor		March 31,		December 31,
	September 30,		December 31,		2019		2018
	2018		2017		(In thousands)
	(In thousands)
$1.0 billion Credit Facility, variable-rate, due March 2021 (1)	$	294,000	$	376,000
$425.0 million New Revolving Credit Facility, variable-rate, due November 2023 (1)					$	270,000	$	294,000
Long-term debt	$	294,000	$	376,000	$	270,000	$	294,000

~~At September 30, 2018,~~ Amplify Energy Operating LLC, our wholly owned subsidiary, ~~(“OLLC”), was~~is a party to a ~~$1.0 billion~~reserve-based revolving credit facility ~~(our “Credit~~(the “New Revolving Credit Facility”), subject to a borrowing base of $425.0 million as of March 31, 2019, which ~~was~~is guaranteed by us and all of our current subsidiaries.

Our borrowing base under our New Revolving Credit Facility ~~was~~is subject to redetermination on at least a semi-annual basis primarily based on a reserve engineering report with respect to our estimated natural gas, oil and NGL reserves, which ~~took~~takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts.

At March 31, 2018, ~~we entered into the Second Amendment~~Amplify Energy Operating LLC, our wholly owned subsidiary (“OLLC”), was a party to ~~the Amended~~a $1.0 billion revolving credit facility (our “Emergence Credit Facility”) which was guaranteed by us and ~~Restated Credit Agreement, dated as~~all 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.~~current subsidiaries.

On November 2, 2018, in connection with entry into ~~the~~our New Revolving Credit Facility, ~~(as defined below),~~ the Emergence 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.full.

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,~~March 31, 2019, we had ~~$2.4~~$1.7 million of letters of credit outstanding, primarily related to operations at our Wyoming properties.

Unamortized deferred financing costs associated with our New Revolving Credit Facility was ~~$4.9~~$4.8 million at ~~September 30, 2018.~~March 31, 2019. At ~~September 30, 2018,~~March 31, 2019, the unamortized deferred financing costs ~~were~~are amortized over the remaining life of our New Revolving 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~~three months ended ~~September 30, 2018:~~March 31, 2019:

On the ~~Effective Date,~~May 4, 2017 (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.

On December 21, 2018, the Company’s board of directors authorized the repurchase of up to $25.0 million of the Company’s outstanding shares of common stock, with repurchases beginning on January 9, 2019. During the three months ended March 31, 2019, the Company repurchased 122,581 shares of common stock at an average price of $7.82 for a total cost of approximately $0.9 million. At March 31, 2019, approximately $24.1 million remains available for repurchase under the program.

The following sets forth the calculation of earnings (loss) per ~~share/unit,~~share, or ~~EPS/EPU,~~EPS, for the periods indicated (in thousands, except per ~~share/unit~~share amounts):

	Successor													Predecessor			For the Three Months Ended
											Period from			Period from			March 31,
	For the Three			For the Three			For the Nine				May 5, 2017			January 1,			2019			2018
	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	)
Net income (loss)																	$	(31,477	)	$	3,239
Less: Net income allocated to participating restricted stockholders		—			—			—				—			—			—			(83	)
Basic and diluted earnings available to common stockholders/limited partners	$	(2,598	)	$	(7,536	)	$	(24,638	)		$	(8,442	)	$	(90,955	)
Basic and diluted earnings available to common stockholders																	$	(31,477	)	$	3,156

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
Common shares outstanding — basic																		22,179			25,000
Dilutive effect of potential common shares																		—			—
Common shares outstanding — diluted																		22,179			25,000

Net earnings per share/unit:
Net earnings per share:
Basic	$	(0.10	)	$	(0.30	)	$	(0.98	)		$	(0.34	)	$	(1.09	)	$	(1.42	)	$	0.13
Diluted	$	(0.10	)	$	(0.30	)	$	(0.98	)	��	$	(0.34	)	$	(1.09	)	$	(1.42	)	$	0.13
Antidilutive stock options (1)		116			517			116				517			—			—			513
Antidilutive warrants (2)		2,174			2,174			2,174				2,174			—			2,174			2,174

~~On the Effective Date in connection with the Plan,~~In May 2017, the Company implemented the ~~MIP for selected employees of the Company or its subsidiaries. An~~Management Incentive Plan (the “MIP”). At March 31, 2019, an aggregate of 2,322,404 shares of the Company’s common stock ~~were~~are reserved for issuance under the MIP. MIP awards are granted in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance awards, stock awards and other incentive awards. To the extent that an award under the MIP is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the MIP. The MIP is administered by the board of directors of the Company.

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~~$4.8 million at ~~September 30, 2018.~~March 31, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately ~~2.2~~2.0 years.

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

				Weighted-					Weighted-
				Average Grant					Average Grant
	Number of			Date Fair Value		Number of			Date Fair Value
	Units			per Unit (1)		Units			per Unit (1)
TSUs outstanding at December 31, 2017 (Successor)		682,792		$	13.54
TSUs outstanding at December 31, 2018							598,024		$	11.35
Granted (2)		256,500		$	10.91		276,398		$	6.92
Forfeited ~~(3)~~		(360,513	)	$	13.57		(17,250	)	$	10.00
Vested		(124,292	)	$	13.77		(276,849	)	$	7.07
TSUs outstanding at September 30, 2018 (Successor)		454,487		$	11.97
TSUs outstanding at March 31, 2019							580,323		$	11.32

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~~$1.3 million at ~~September 30, 2018.~~March 31, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.4 years.

During the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, the ~~board of directors~~Company granted PSUs to certain ~~executives~~new employees 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

Share price targets	$	12.50		$	15.00		$	17.50

Risk-free interest rate:
Awards Issued on January 1, 2019		2.44	%		2.44	%		2.44	%

Dividend yield		—			—			—

Expected volatility:
Awards Issued on January 1, 2019		54.0	%		54.0	%		54.0	%

Calculated fair value per PSU:
Awards Issued on January 1, 2019	$	6.76		$	5.86		$	5.11

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:~~

				Weighted-					Weighted-
				Average Grant					Average Grant
	Number of			Date Fair Value		Number of			Date Fair Value
	Options			per Option (1)		Units			per Unit (1)
Restricted stock options outstanding at December 31, 2017 (Successor)		517,398		$	5.01
PSUs outstanding at December 31, 2018							393,500		$	8.14
Granted(2)		—		$	—		7,750		$	5.91
Forfeited		(36,127	)	$	5.01		(13,250	)	$	7.59
Vested		(365,654	)	$	5.01		—		$	—
Restricted stock options outstanding at September 30, 2018 (Successor)		115,617		$	5.01
PSUs outstanding at March 31, 2019							388,000		$	8.11

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~~$0.2 million at ~~September 30, 2018.~~March 31, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately ~~2.3~~1.8 years.

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

				Weighted-					Weighted-
				Average Grant					Average Grant
	Number of			Date Fair Value		Number of			Date Fair Value
	Units			per Unit (1)		Units			per Unit (1)
Board RSUs outstanding at December 31, 2017 (Successor)		16,341		$	13.77
Board RSUs outstanding at December 31, 2018							39,604		$	11.36
Granted ~~(2)~~		28,708		$	10.45		—		$	—
Forfeited		—		$	—		—		$	—
Vested		(5,445	)	$	13.77		(10,809	)	$	11.57
Board RSUs outstanding at September 30, 2018 (Successor)		39,604		$	11.36
Board RSUs outstanding at March 31, 2019							28,795		$	11.29

The following table summarizes the amount of recognized compensation expense associated with the MIP and 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

	For the Three Months Ended
	March 31,
	2019		2018
Equity classified awards
TSUs	$	669	$	948
PSUs		396		—
Board RSUs		113		19
Restricted stock options		—		209
	$	1,178	$	1,176

As discussed in Note 2, the Company adopted ASU 842, leases, on January 1, 2019 using the modified retrospective approach with a cumulative impact to retained earnings. The adoption of this standard has resulted in an increase in the assets and liabilities on the Company’s Unaudited Condensed Consolidated Balance Sheet. The Company has completed the review and evaluation of current and potential leases which resulted primarily in our corporate office lease and some minor equipment and vehicle leases qualifying under the new guidance. Based upon this analysis, the impact of the new guidance established a liability and the corresponding asset of $5.4 million at January 1, 2019.

For the quarter ended March 31, 2019, our leases qualify as operating leases and we did not have any existing or new leases qualifying as financing leases. We have leases for office space and equipment in our corporate office and operating regions as well as vehicles, compressors and surface rentals related to our business operations. In addition, we have offshore Southern California pipeline right-of-way use agreements. Most of our leases, other than our corporate office lease, have an initial term and may be extended on a month-to-month basis after expiration of the initial term. Most of our leases can be terminated with 30-day prior written notice. The majority of our month-to-month leases are not included as a lease liability in our balance sheet under ASC 842 because continuation of the lease is not reasonably certain. Additionally, the Company elected the short-term practical expedient to exclude leases with a term of twelve months or less.

Our corporate office lease does not provide an implicit rate. To determine the present value of the lease payments, we use our incremental borrowing rate based on the information available at the inception date. To determine the incremental borrowing rate, we apply a portfolio approach based on the applicable lease terms and the current economic environment. We use a reasonable market interest rate for our office equipment and vehicle leases.

The following table presents the Company’s right-of-use assets and lease liabilities as of March 31, 2019.

The following table reflects the Company’s maturity analysis of the minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):

The following is a schedule of the Company’s future contractual payment for operating leases prepared in accordance with accounting standards prior to the adoption of ASC 842, as of December 31, 2018:

The weighted average remaining lease terms and discount rate for all of our operating leases were as follow as of March 31, 2019:

We have instituted internal controls going forward to monitor and evaluate new leases for appropriate accounting under the new guidance.

Note 13. Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Consolidated Statements of Cash Flows

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

	Successor		Successor		March 31,		December 31,
	September 30,		December 31,		2019		2018
	2018		2017
Accrued lease operating expense					$	9,090	$	10,469
Accrued interest payable						3,724		2,476
Accrued capital expenditures						2,602		4,349
Accrued general and administrative expense	$	4,832	$	4,412		2,398		4,393
Accrued lease operating expense		8,827		6,439
Accrued capital expenditures		3,744		3,854
Accrued exploration expense		252		—
Operating lease liability						1,921		—
Accrued ad valorem tax		2,099		398		987		729
Asset retirement obligations		438		713		477		477
Accrued interest payable		145		1,309
Other		8		1,108		—		262
Accrued liabilities	$	20,345	$	18,233	$	21,199	$	23,155

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

	Successor		Successor
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Cash and cash equivalents	$	11,862	$	6,392	$	24,876	$	49,704
Restricted cash		325		—		325		325
Total cash, cash equivalents and restricted cash	$	12,187	$	6,392	$	25,201	$	50,029

	Successor					Predecessor
	For The			Period from		Period from
	Nine Months			May 5, 2017		January 1, 2017		For the Three Months Ended
	Ended			through		through		March 31,
	September 30, 2018			September 30, 2017		May 4, 2017		2019			2018
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	15,405		$	7,039	$	6,598	$	2,325		$	6,028
Cash paid for reorganization items, net		2,004			7,333		11,999		187			656
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(565	)		12,636		3,173		(2,612	)		1,890

There have been no transactions in excess of $120,000 between us and aany related person in which the related person had a direct or indirect material interest for the three ~~or nine~~ months ended ~~September 30,~~March 31, 2019 and 2018, ~~for the period from January 1, 2017 through May 4, 2017, or the period from May 5, 2017 through September 30, 2017.~~respectively.

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~~March 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~~March 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~~March 31, 2019 and December 31, ~~2017,~~2018, 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 Southern California. ~~The trust account (the “Beta Decommissioning Trust Account”) had the required minimum balance~~Beta’s decommissioning obligations remain fully supported by A-rated surety bonds and $90.0 million of ~~$152.0 million at September 30, 2018 and December 31, 2017 and was fully cash funded.~~cash. The held-to-maturity investments held in the ~~Beta Decommissioning Trust Account~~trust account at ~~September 30, 2018~~March 31, 2019 for the U.S. Bank money market cash equivalent was ~~$152.5~~$90.2 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.later in 2019.

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 less than $0.1 million income tax benefit/(expense) for the three months ended March 31, 2019 and 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.March 31, 2018. The Company’s effective tax rate was 0.0% for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 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.~~respectively. The effective tax rates for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018 are different from the statutory U.S. federal income tax rate primarily due to our ~~existing~~recorded 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~~On May 5, 2019, the Company, Midstates Petroleum Company, Inc. (“Midstates”) and Midstates Holdings, Inc., a direct, wholly owned subsidiary of Midstates (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which, in an all-stock transaction, the Company will merge with and into Merger Sub, with the Company surviving as a wholly owned subsidiary of Midstates (the “Merger”). Pursuant to the ~~Beta Decommissioning Trust Account.~~Merger Agreement, Amplify Energy stockholders will receive 0.933 shares of Midstates common stock, par value $0.01 per share, for each share of Amplify Energy common stock that they hold (such newly issued common stock, the “Stock Issuance”). Following the closing of the Merger, current Amplify Energy and Midstates stockholders will each own 50% of the outstanding stock of the combined company.

~~New Revolving~~Completion of the Merger is subject to the terms and conditions set forth in the Merger Agreement, including holders of a majority of votes cast by Midstates stockholders at the special meeting voting in favor of the Stock Issuance, holders of a majority of the issued and outstanding shares of Amplify common stock voting in favor of the Merger, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and other customary closing conditions. Subject to the terms and conditions set forth in the Merger Agreement, the Merger is expected to close in the third quarter of 2019.

The foregoing description of the Merger Agreement is qualified in its entirety by reference to the Merger Agreement, which is attached as Exhibit 2.1 to the Company’s current report on Form 8-K filed on May 6, 2019.

~~See Note 8 for additional information relating~~On May 5, 2019, OLLC entered into the First Amendment to ~~our entrance into~~Credit Agreement, among OLLC, Amplify Acquisitionco Inc., Amplify Energy, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “First Amendment”).

The First Amendment amends the New Revolving Credit Facility ~~and,~~to, among other things (i) modify certain defined terms in connection ~~therewith,~~with the ~~termination~~completion of the transactions contemplated by the Merger Agreement, including the Merger; (ii) allow certain structural changes for tax planning activities; and ~~repayment~~(iii) modify certain covenants in the New Revolving Credit Facility that restrict Amplify Energy’s ability to take certain actions or engage in certain business such that, once the First Amendment is effective, the occurrence of ~~our~~such actions or business in connection with the Merger Agreement or completion of the transactions contemplated thereby, including the Merger, will not be so restricted.

Certain of the modifications to the New Revolving Credit ~~Facility.~~Facility, including those permitting pre-Merger tax restrictions, became effective upon the signing of the First Amendment. The remaining modifications become effective concurrently with the consummation of the Merger, subject to certain closing conditions.

The First Amendment also contains customary representations, warranties and agreements of OLLC and the guarantors. All other material terms and conditions of the New Revolving Credit Facility were unchanged by the First Amendment.

The foregoing description of the First Amendment is qualified in its entirety by reference to the First Amendment, which is attached as Exhibit 10.1 to the Company’s current report on Form 8-K filed on May 6, 2019.

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,~~2018, filed with the SEC on March ~~12,~~ 6, 2019 (“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~~the Rockies, in federal waters offshore ~~California.~~Southern California, East Texas / North Louisiana and South Texas. 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:~~2018:

On ~~November 2, 2018,~~May 5, 2019, the Company, Midstates Petroleum Company, Inc. (“Midstates”) and Midstates Holdings, Inc., a direct, wholly owned subsidiary of Midstates (“Merger Sub”) entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which, in an all-stock transaction, the Company will merge with and into Merger Sub, with the Company surviving as a wholly owned subsidiary of Midstates (the “Merger”). Pursuant to the Merger Agreement, Amplify Energy stockholders will receive 0.933 shares of Midstates common stock, par value $0.01 per share, for each share of Amplify Energy common stock that they hold (such newly issued common stock, the “Stock Issuance”). Following the closing of the Merger, current Amplify Energy and Midstates stockholders will each own 50% of the outstanding stock of the combined company. Following the closing of the Merger, current Amplify Energy and Midstates stockholders will each own 50% of the outstanding stock of the combined company and the combined company will continue to operate under the Amplify brand.

The boards of directors of both the Company and Midstates have unanimously approved the Merger Agreement and have recommended that their respective stockholders vote their shares in favor of the Merger or the Stock Issuance, as applicable.

Completion of the Merger is subject to the terms and conditions set forth in the Merger Agreement, including holders of a majority of votes cast by Midstates stockholders at the special meeting voting in favor of the Stock Issuance, holders of a majority of the issued and outstanding shares of Amplify common stock voting in favor of the Merger, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and other customary closing conditions. The Company sought, and has received, a technical consent from the lenders in its existing credit facility permitting the consummation of the Merger. Subject to the terms and conditions set forth in the Merger Agreement, the Merger is expected to close in the third quarter of 2019.

On May 5, 2019, Amplify Energy Operating LLC (“OLLC”), a wholly owned subsidiary of Amplify Energy, entered into the First Amendment to Credit Agreement, among 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”) withAmplify Energy, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent ~~(in such capacity,~~(the “First Amendment”).

The First Amendment amends the ~~“Agent”) and an issuer~~parties’ existing Credit Agreement, dated as of ~~letters of credit, and the other lenders and agents from time to time party thereto. The New~~November 2, 2018 (the “New Revolving Credit ~~Facility matures on November 2, 2023.~~

~~The New Revolving Credit Facility is subject~~Facility”) 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.

~~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~~(i) modify 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~~defined terms in connection with the ~~following financial covenants: (i) as~~completion of the ~~date of determination,~~transactions contemplated by the ~~ratio of total debt to EBITDAX (as defined~~Merger Agreement, including the Merger; (ii) allow certain structural changes for tax planning activities; and (iii) modify certain covenants 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.

~~The Company’s obligations under~~ the New Revolving Credit Facility ~~are secured by mortgages on not less than 85%~~that restrict Amplify Energy’s ability to take certain actions or engage in certain business such that, once the First Amendment is effective, the occurrence of such actions or business in connection with the Merger Agreement or completion of the ~~PV-9 value of oil and gas properties (and at least 85%~~transactions contemplated thereby, including the Merger, will not be so restricted.

Certain of the ~~PV-9 value~~modifications to the New Revolving Credit Facility, including those permitting pre-Merger tax restrictions, became effective upon the signing of the ~~proved, developed and producing oil and gas properties) included in~~First Amendment. The remaining modifications become effective concurrently with the ~~determination~~consummation of the ~~borrowing base.~~Merger, subject to certain closing conditions.

The First Amendment also contains customary representations, warranties and agreements of OLLC and ~~our~~the guarantors. All other ~~subsidiaries entered into a Pledge~~material terms and ~~Security Agreement in favor~~conditions of the ~~Agent for~~New Revolving Credit Facility were unchanged by the ~~secured parties,~~First Amendment.

On March 22, 2019, P. Michael Highum resigned from the board of directors of the Company. Mr. Highum served on the Company’s audit committee. There were no known disagreements between Mr. Highum and the Company which led to Mr. Highum’s resignation from the board of directors of the Company.

On March 22, 2019, Scott L. Hoffman was appointed to the board of directors of the Company. Mr. Hoffman has been appointed to the audit committee of the board of directors. There are no arrangements or understandings between Mr. Hoffman and any other persons pursuant to which ~~OLLC’s obligations under the New Credit Agreement are secured by~~Mr. Hoffman was selected as 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~~director 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.

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.Company.

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~~2018 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.

Beginning in 2019, the Company elected to change its reporting convention from natural gas equivalent (Mcfe) to barrels of oil equivalent (Boe). The change in presentation reflects our liquids-weighted production and reserve profile with a balanced approach to development of our oil and natural gas asset portfolio. The Company’s proved reserves as of year-end 2018 were 50% crude oil, 15% natural gas liquids and 35% natural gas.

The results of operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 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			For the Three Months Ended
	Months Ended			through			through			March 31,
	September 30, 2018			September 30, 2017			May 4, 2017			2019			2018
	($ In thousands)						($ In thousands)			($ In thousands)
Oil and natural gas sales	$	264,187		$	117,762		$	108,970		$	65,067		$	87,847
Lease operating expense		84,575			47,961			35,568			28,910			29,570
Gathering, processing and transportation		17,772			11,191			10,772			4,657			5,600
Exploration expense		3,031			11			21
Taxes other than income		15,289			6,147			5,187			4,409			5,037
Depreciation, depletion and amortization		39,932			21,818			37,717			11,166			12,958
General and administrative expense		35,739			18,479			31,606			9,308			10,657
Accretion of asset retirement obligations		4,419			2,692			3,407			1,311			1,718
(Gain) loss on commodity derivative instruments		67,218			12,302			(23,076	)		32,487			10,456
(Gain) loss on sale of properties		1,439			—			—			—			2,373
Interest expense, net		(17,395	)		(9,605	)		(10,243	)		(4,089	)		(5,772	)
Reorganization items, net		(1,752	)		(382	)		(88,774	)		(187	)		(518	)
Income tax benefit (expense)		—			4,940			91			50			—
Net income (loss)		(24,638	)		(8,442	)		(90,955	)		(31,477	)		3,239

Oil and natural gas revenue:
Oil sales	$	165,843		$	62,820		$	55,767		$	40,057		$	54,726
NGL sales		34,009			14,039			14,103			5,865			10,946
Natural gas sales		64,335			40,903			39,100			19,145			22,175
Total oil and natural gas revenue	$	264,187		$	117,762		$	108,970		$	65,067		$	87,847

Production volumes:
Oil (MBbls)		2,579			1,450			1,204			752			902
NGLs (MBbls)		1,167			658			616			265			412
Natural gas (MMcf)		22,575			13,250			12,411			5,490			7,775
Total (MMcfe)		45,053			25,893			23,336
Average net production (MMcfe/d)		165.0			173.8			188.2
Total (Boe)											1,932			2,610
Average net production (MBoe/d)											21.5			29.0

Average sales price:
Oil (per Bbl)	$	64.30		$	43.35		$	46.28		$	53.28		$	60.66
NGL (per Bbl)		29.14			21.34			22.90			22.09			26.57
Natural gas (per Mcf)		2.85			3.09			3.15			3.49			2.85
Total (per Mcfe)	$	5.86		$	4.55		$	4.67
Total (per MBoe)										$	33.67		$	33.66

Average unit costs per Mcfe:
Average unit costs per MBoe:
Lease operating expense	$	1.88		$	1.85		$	1.52		$	14.96		$	11.33
Gathering, processing and transportation		0.39			0.43			0.46			2.41			2.15
Taxes other than income		0.34			0.24			0.22			2.28			1.93
General and administrative expense		0.79			0.71			1.35			4.82			4.08
Depletion, depreciation and amortization		0.89			0.84			1.62			5.78			4.97

For the three months ended ~~September 30, 2018 and~~March 31, 2019 compared to the three months ended ~~September 30, 2017~~March 31, 2018

Net ~~losses~~loss of ~~$2.6~~$31.5 million and ~~$7.5~~net income of $3.2 million were recorded for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively.

Oil, natural gas and NGL revenues were ~~$85.4~~$65.1 million and ~~$75.5~~$87.8 million for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. Average net production volumes were approximately ~~152.4 MMcfe/~~21.5 MBoe/d and ~~177.4 MMcfe/~~29.0 MBoe/d for the three months ended ~~September 30,~~March 31, 2019 and 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~~$33.67 per ~~Mcfe~~MBoe and ~~$4.63~~$33.66 per ~~Mcfe~~MBoe for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. ~~The increase was primarily due to increases in realized prices for oil and NGLs.~~

Lease operating expense was ~~$27.5~~$28.9 million and ~~$29.1~~$29.6 million for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. The change in lease operating expense was primarily related to lower production. On a per ~~Mcfe~~MBoe basis, lease operating expense was ~~$1.96~~$14.96 and ~~$1.78~~$11.33 for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. The change in lease operating expense on a per MBoe basis was primarily due to lower production.

Gathering, processing and transportation was ~~$6.2~~$4.7 million and ~~$7.1~~$5.6 million for the three months ended ~~September 30,~~March 31, 2019 and 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.~~production. On a per ~~Mcfe~~MBoe basis, gathering, processing and transportation was ~~$0.44~~$2.41 and ~~$0.43~~$2.15 for ~~each of~~ the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively.

Taxes other than income was ~~$4.7~~$4.4 million and ~~$4.2~~$5.0 million for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. On a per ~~Mcfe~~MBoe basis, taxes other than income were ~~$0.34~~$2.28 and ~~$0.26~~$1.93 for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. The change in taxes other than income on a per ~~Mcfe~~MBoe basis was primarily due to an increase in commodity price.

DD&A expense was ~~$13.4~~$11.2 million and ~~$13.5~~$13.0 million for the three months ended ~~September 30,~~March 31, 2019 and 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~~$9.3 million and ~~$11.1~~$10.7 million for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. Non-cash share-based compensation expense was ~~$1.6~~$1.9 million and ~~$1.0~~$1.2 million for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively.

Net losses on commodity derivative instruments of ~~$21.1~~$32.5 million were recognized for the three months ended ~~September 30, 2018,~~March 31, 2019, consisting of ~~$20.5~~$31.2 million decrease in the fair value of open positions and ~~$0.6~~$1.3 million of cash settlements paid on expired positions. Net losses on commodity derivative instruments of ~~$14.2~~$10.5 million were recognized for the three months ended ~~September 30, 2017,~~March 31, 2018, consisting of $4.8 million of cash settlement receipts on expired positions offset by a ~~$27.2~~$15.3 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~~$4.1 million and $5.8 million for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. ~~The Company recognized $0.5~~Interest expense, net for 2019 included losses of interest rate swaps of approximately $0.1 million and ~~$0.6 million in~~ amortization ~~and write-off~~ of deferred financing ~~costs~~fees of $0.3 million. Interest expense, net for 2018 included amortization of deferred financing fees of $0.5 million. The change in interest expense is primarily due to a $1.5 million reduction in interest expense due to lower outstanding borrowings for the three months ended ~~September 30, 2018 and 2017, respectively.~~March 31, 2019.

Average outstanding borrowings under our New Revolving Credit Facility were ~~$306.7 million and $411.2~~$278.0 million for the three months ended ~~September 30, 2018 and 2017, respectively.~~March 31, 2019. Average outstanding borrowings under our Emergence Credit Facility were $364.2 million for the three months ended March 31, 2018.

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 $0.2 million and $0.5 million for the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and less than $0.1 million for the three months ended September 30, 2017.~~respectively. 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,			For the Three Months Ended
	Months Ended			Months Ended			Months Ended			through			2017 through			March 31,
	September 30, 2018			September 30, 2017			September 30, 2018			September 30, 2017			May 4, 2017			2019			2018
	(In thousands)												(In thousands)			(In thousands)
Net income (loss)	$	(2,598	)	$	(7,536	)	$	(24,638	)	$	(8,442	)	$	(90,955	)	$	(31,477	)	$	3,239
Interest expense, net		5,336			5,808			17,395			9,605			10,243			4,089			5,772
Income tax expense (benefit)		—			(4,348	)		—			(4,940	)		(91	)		(50	)		—
DD&A		13,355			13,467			39,932			21,818			37,717			11,166			12,958
Accretion of AROs		1,272			1,665			4,419			2,692			3,407			1,311			1,718
(Gains) losses on commodity derivative instruments		21,110			14,217			67,218			12,302			(23,076	)		32,487			10,456
Cash settlements received (paid) on expired commodity derivative instruments		(616	)		12,992			6,287			21,276			15,895			(1,277	)		4,876
(Gain) loss on sale of properties		(707	)		—			1,439			—			—			—			2,373
Acquisition and divestiture related expenses		82			238			969			238			—			364			208
Share/Unit-based compensation expense		1,578			1,016			3,090			1,543			3,667
Share-based compensation expense																	1,936			1,176
Exploration costs		9			4			3,031			—			16			15			34
(Gain) loss on settlement of AROs		639			284			529			284			36			143			—
Restructuring related costs		—			—			—			—			7,548
Bad debt expense																	101			—
Reorganization items, net		466			33			1,752			382			88,774			187			518
Severance payments		(258	)		—			7,451			—			—			39			—
Other		—			—			(105	)		—			57
Adjusted EBITDA	$	39,668		$	37,840		$	128,769		$	56,758		$	53,238		$	19,034		$	43,328

	Successor												Predecessor
										Period from			Period from
	For the Three			For the Three			For the Nine			May 5, 2017			January 1,			For the Three Months Ended
	Months Ended			Months Ended			Months Ended			through			2017 through			March 31,
	September 30, 2018			September 30, 2017			September 30, 2018			September 30, 2017			May 4, 2017			2019			2018
	(In thousands)												(In thousands)			(In thousands)
Net cash provided by (used in) operating activities	$	32,335		$	37,330		$	116,610		$	50,313		$	125,498		$	10,800		$	42,147
Changes in working capital		1,336			(6,358	)		(17,214	)		(4,219	)		(16,524	)		3,006			(4,810	)
Interest expense, net		5,336			5,808			17,395			9,605			10,243			4,089			5,772
Cash settlements received on terminated derivatives		—			—			—			—			(94,146	)
Gain (loss) on interest rate swaps																	94			—
Amortization of deferred financing fees		(497	)		(570	)		(2,249	)		(916	)		—			(308	)		(541	)
Acquisition and divestiture related expenses		82			238			969			238			—			364			208
Income tax expense (benefit) - current portion		—			897			—			897			(17	)		(50	)		—
Exploration costs		9			4			3,031			—			16			15			34
Plugging and abandonment cost		859			458			1,129			458			200			305			—
Restructuring related costs		—			—			—			—			7,548
Reorganization items, net		466			33			1,752			382			20,420			187			518
Severance payments		(258	)		—			7,451			—			—			39			—
Other		—			—			(105	)		—			—			493			—
Adjusted EBITDA	$	39,668		$	37,840		$	128,769		$	56,758		$	53,238		$	19,034		$	43,328

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,~~2019, 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 25% - 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,~~March 31, 2019, 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~~$13.1 million for the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, which were primarily related to drilling, capital workovers and facilities located in ~~East Texas~~the Rockies 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 Southern California may further increase. The implementation of this increase is currently on hold and we do not expect resolution of a negotiated decommissioning estimate until ~~2019 or later.~~later in 2019. At ~~September 30, 2018,~~March 31, 2019, there was approximately ~~$152.5~~$90.2 million in the trust account and ~~$62.0~~$71.3 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,~~March 31, 2019, we had a working capital ~~deficit~~ of ~~$42.6~~$1.3 million primarily due to a cash balance of $24.9 million and accounts receivable of $25.1 million partially offset by the timing of accruals, which included accrued liabilities of ~~$20.3~~$21.2 million, revenues payable of ~~$24.3~~$24.1 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~~$9.1 million.

New Revolving Credit Facility. On ~~May 4, 2017,~~November 2, 2018, OLLC as borrower, entered into the New Revolving Credit ~~Agreement~~Facility with ~~Wells Fargo~~ Bank ~~National Association,~~of Montreal, 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,~~March 31, 2019, our borrowing base under our New Revolving 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~~takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts.

On 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,~~March 31, 2019, was ~~$390.0~~approximately $425.0 million.

As of ~~September 30, 2018,~~March 31, 2019, we were in compliance with all the financial (interest coverage ratio, current ratio and total leverage ratio) and other covenants associated with our New Revolving Credit Facility.

As of ~~September 30, 2018,~~March 31, 2019, we had approximately ~~$93.6~~$153.4 million of available borrowings under our New Revolving Credit Facility, net of ~~$2.4~~$1.7 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~~our 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.Facility.

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 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~~$10.8 million ~~$50.3~~ and ~~$125.5 million~~$42.1 for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 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, 173.8MMcfe/~~21.5 MBoe/d and ~~188.2 MMcfe/~~29.0MBoe/d for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 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~~$33.67 per ~~Mcfe, $4.55~~MBoe and $33.66 per ~~Mcfe and $4.67 per Mcfe~~MBoe for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 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~~$28.9 million and ~~$35.6~~$29.6 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 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~~$4.7 million and ~~$10.8~~$5.6 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 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~~three months ended ~~September 30, 2018~~March 31, 2019 was ~~$28.0~~$10.5 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$10.4 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~~three months ended March 31, 2018 was ~~$6.5~~$13.3 million, of which ~~$6.2~~$13.1 million was used for additions to oil and natural gas properties.

Financing Activities. The Company had net repayments of ~~$82.0~~$24.0 million related to our New Revolving Credit Facility and ~~$27.0~~$29.0 million under the Emergence Credit Facility for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 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~~three months ended ~~September 30, 2018,~~March 31, 2019, there were no significant changes in our consolidated contractual obligations from those reported in our ~~2017~~2018 Form 10-K except for the Credit Facility borrowings and repayments.

As of ~~September 30, 2018,~~March 31, 2019, we had no off–balance sheet arrangements.

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~~2018 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~~Emergence Credit Facility and our New Revolving 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,~~March 31, 2019, see Note 6 of the Notes to Unaudited Condensed Consolidated Financial Statements included “Item 1. Financial Statements” of this quarterly report.

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 6 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for interest rate swap arrangements that were outstanding at March 31, 2019.

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,~~March 31, 2019, 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~~$0.1 million against amounts outstanding under our New Revolving Credit Facility at ~~September 30, 2018.~~March 31, 2019.

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.~~March 31, 2019.

No changes in our internal control over financial reporting occurred during the quarter ended ~~September 30, 2018~~March 31, 2019 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,~~15, “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~~In addition to the risk factors ~~since those~~ disclosed in our ~~2017~~2018 Form ~~10-K.~~10-K, we face risk factors relating to the Merger, including the following:

We may fail to complete the Merger in the anticipated time frame or at all. Our failure to complete the Merger could adversely affect the market price of our common stock and otherwise adversely affect our business, results of operations and financial condition.

The completion of the Merger is not assured and is subject to a number of conditions and risks, including conditions and risks that are outside of our control. The Merger Agreement contains a number of conditions that must be satisfied or waived prior to the completion of the Merger. There can be no assurance that all of the conditions to the completion of the Merger will be so satisfied or waived. For example, holders of a majority of votes cast by Midstates stockholders at the special meeting may not vote in favor of the Stock Issuance, holders of a majority of the issued and outstanding shares of Amplify common stock may not vote in favor of the Merger or we or Midstates may fail to receive any required regulatory approvals. If any of these conditions are not satisfied or waived, we will be unable to complete the Merger.

If we fail to complete the Merger, our ongoing business may be adversely affected and we will not realize any of the anticipated benefits of the Merger. For example, our failure to complete the Merger may result in negative publicity or a negative impression of us in the investment community, which may adversely affect the market price of our common stock, and may affect our relationships with our customers, suppliers, employees and other business partners. In addition, even if we fail to complete the Merger, we will still incur certain significant costs associated with the Merger, primarily consisting of legal fees, accounting fees, financial advisory, financial printing and other related costs. Furthermore, pursuant to the Merger Agreement, if the Merger is not completed, in certain specified circumstances, we may be required to pay Midstates a termination fee in the amount of $4.5 million. Accordingly, if the Merger is not completed, or if there are significant delays in completing the Merger, the trading price of our common stock and our business, results of operations and financial condition could be adversely affected.

We are subject to business uncertainties while the Merger is pending, which could adversely affect our business, results of operations and financial condition.

While the Merger is pending, our customers, suppliers, employees and other business partners may delay or defer certain business decisions with respect to us or seek to terminate, change or renegotiate their relationships with us as a result of the Merger. Any of these developments could adversely affect our business, results of operations and financial condition, as well as the market price of our common stock, regardless of whether the Merger is completed.

In addition, under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to the completion of the Merger, which may adversely affect our ability to execute certain of our business strategies, including our ability to enter into contracts, acquire or dispose of assets or incur indebtedness or capital expenditures. These contractual restrictions could negatively affect our business, results of operations and financial condition while the Merger is pending.

Pursuant to the Merger Agreement, our stockholders will receive 0.933 shares of Midstates common stock for each share of Amplify Energy common stock that they hold. Accordingly, the Merger will dilute the ownership position of our current stockholders in the combined company. We currently estimate that our current stockholders will own approximately 50 percent of the issued and outstanding shares of Midstates immediately following the completion of the Merger.

Because the exchange ratio pursuant to the Merger Agreement is fixed, our stockholders cannot be certain of the market value of the shares of Midstates common stock that they will receive in connection with the Merger relative to the value of the shares of Amplify Energy common stock that they currently hold.

Pursuant to the Merger Agreement, our stockholders will receive 0.933 shares of Midstates common stock for each share of Amplify Energy common stock that they hold. There is no mechanism in the Merger Agreement that would adjust the number of shares of Midstates common stock that our stockholders will receive based on any decreases or increases in the trading price of shares of Midstates common stock. Accordingly, the market value of the consideration that our stockholders will receive in connection with the Merger will depend on the respective market prices of our common stock and Midstates’ common stock at the closing of the Merger.

The respective market prices of our common stock and Midstates’ common stock may be highly volatile and could fluctuate significantly for various reasons, including:

•changes in market assessments of the likelihood that the Merger will be completed;

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

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

Furthermore, while the Merger is pending, the market price of our common stock could be negatively affected by risks and conditions that apply to Midstates, which may be different from the risks and conditions currently applicable to our business.

Even if the Merger is completed, the integration of our business with that of Midstates may be more difficult, costly or time consuming than we expect and we may fail to realize the anticipated benefits of the Merger fully or at all.

The success of the Merger will depend on our and Midstates’ ability to successfully combine and integrate our respective businesses. Even if the Merger is completed, there can be no assurance that we and Midstates will be able to successfully combine and integrate our respective businesses or otherwise realize the anticipated benefits of the Merger. The combined company may perform differently than we expect. Potential difficulties that we and Midstates may face in the integration process include: the inability to successfully integrate our respective businesses in a manner that permits the combined company to achieve the full revenue and cost savings anticipated from the transaction; complexities associated with managing a larger and more complex business; challenges integrating personnel from the two companies and the loss of key employees; potential unknown liabilities and unforeseen expenses, delays or regulatory conditions in connection with the Merger or the integration process; difficulties integrating relationships with customers, suppliers, employees and other business partners; and poorer performance at one or both of the companies as a result of the diversion of our or Midstates’ respective management’s attention in connection with the Merger or the integration process. If we experience any of these difficulties or other problems in connection the integration process, we and Midstates may fail to realize the anticipated benefits of the Merger fully or at all.

We and Midstates have incurred and we expect to continue to incur significant non-recurring transaction-related costs associated with completing the Merger, combining the operations of the two companies and achieving desired synergies. Transaction costs include legal fees, accounting fees, financial advisory, financial printing and other related costs. These costs may be substantial and, in many cases, will be borne by us whether or not the Merger is completed. We will also incur costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. Even if the Merger is completed, the benefits of the Merger may not offset transaction costs or allow the combined company to achieve a net benefit in the near term, or at all.

We or Midstates may become the target of securities class action or derivative lawsuits that could result in substantial costs and may delay or prevent the Merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements. Defending against these claims can result in substantial costs and divert management time and resources, even if the lawsuits are without merit. An adverse judgment could result in monetary damages, which could have a negative impact on our and Midstates’ respective businesses, results of operations and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, the injunction may delay or prevent the Merger from being completed, which may adversely affect our and Midstates’ respective businesses, results of operations and financial condition.

The following table summarizes our repurchase activity during the three months ended ~~September 30, 2018:~~March 31, 2019:

Period

Total Number of Shares Purchased

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs

Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs

(In thousands)
Common Shares Repurchased (1)

July 1, 2018 - July 31, 2018 (Successor)

5,600

$
11.00

n/a

n/a
August 1, 2018 - August 31, 2018 (Successor)

—

$
—

n/a

n/a
September 1, 2018 - September 30, 2018 (Successor)

—

$
—

n/a

n/a

Period

Total Number of Shares Purchased

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs

Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (1)

(In thousands)

Common Shares Repurchased (1)

January 1, 2019 - January 31, 2019

—

n/a

—

n/a

February 1, 2019 - February 28, 2019

—

n/a

—

n/a

March 1, 2019 - March 31, 2019

88,508

6.94

—

n/a

On ~~November 2, 2018, Amplify Energy Operating LLC (“OLLC”)~~May 1, 2019, the Company approved new compensatory arrangements for Messrs. Willsher, Smiley and ~~Amplify Acquisitionco, Inc., wholly owned subsidiaries of~~Willis. On May 3, 2019, the Company entered into employment agreements with each of Messrs. Willsher, Smiley and Willis (each, an “Employment Agreement” and collectively, the “Employment Agreements”), memorializing the previously approved compensatory arrangements and setting forth terms and conditions under which each will serve as an executive officer of the Company.

Mr. Willsher’s Employment Agreement provides Mr. Willsher with an initial base salary of $300,000 per year; an annual bonus opportunity (the “Annual Bonus”) (targeted at 75% of his annual base salary) (the “Target Bonus”); the potential to receive long-term incentive compensation awards as determined in the Board’s discretion; the right to participate in the benefit plans, programs and arrangements available to the Company’s other senior executives generally, subject to the terms and conditions of such plans, programs and arrangements; and reimbursement for his business expenses incurred during the employment term.

Upon any termination of employment with the Company, Mr. Willsher will be entitled to: (i) his accrued but unpaid base salary as of the termination date, (ii) any unreimbursed business expenses incurred through the termination date and (iii) any payments and benefits to which he may be entitled under any benefit plans, programs, or arrangements (collectively, the “Accrued Obligations”).

In the event of a ~~credit agreement~~termination of Mr. Willsher’s employment with the Company without “cause” (as defined below) or for “good reason” (as defined below) (each, a “Good Leaver Termination”), then in addition to the Accrued Obligations and subject to his timely execution and non-revocation of a general release of claims, and complying with the release and the restrictive covenants, Mr. Willsher will be entitled to: (i) any earned but unpaid Annual Bonus for the preceding calendar year (the ~~“New Credit Agreement”~~“Actual Full Year Bonus”) ~~providing~~; (ii) a pro-rated Annual Bonus in respect of the calendar year of termination, with the amount determined based on actual results for such calendar year and with the pro-ration determined based on the duration of his employment with the Company during such calendar year (the “Pro-Rated Bonus”); (iii) (A) if the termination date occurs on or prior to December 11, 2019, an amount equal to Mr. Willsher’s then-current monthly base salary rate, and (B) if the termination occurs after December 11, 2019, an amount equal to 200% of his then-current monthly base salary rate, in each case, payable in accordance with the Company’s regularly scheduled payroll practices for a ~~new $425.0 million reserve-based revolving credit facility (the “New Revolving Credit Facility”)~~period of 12 months following the termination date; and (iv) up to 12 months of continued health insurance benefits under the Company group health plan (at the employee-rate), subject to his continued eligibility for COBRA coverage and terminable if he obtains other employment offering group health plan coverage.

If Mr. Willsher’s employment with ~~Bank of Montreal, as administrative agent (in such capacity,~~ the ~~“Agent”) and an issuer of letters of credit,~~Company is terminated due to his death or “disability” (as defined in the Employment Agreement), then in addition to the Accrued Obligations, Mr. Willsher will be entitled to the Actual Full Year Bonus and the ~~other lenders and agents from time to time party thereto. The New Revolving Credit Facility matures on November 2, 2023.~~

~~The New Credit~~Employment Agreement, ~~contains negative covenants that limit our and our subsidiaries’ ability, among other things,~~the Company will have “cause” 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,~~terminate Mr. Willsher’s employment upon the occurrence of ~~certain Events~~any of ~~Default (as defined in the New Credit Agreement). Such Events~~his: (i) conviction of ~~Default include customary events~~a felony, or plea of ~~default for a financing agreement~~guilty or nolo contendere to, any felony or any crime of ~~this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in~~moral turpitude; (ii) repeated intoxication by alcohol or drugs during the performance of ~~affirmative~~his duties; (iii) embezzlement or ~~negative covenants, defaults~~other willful and intentional misuse of any of the funds of the Company or its direct or indirect subsidiaries, (iv) commission of a demonstrable act of fraud; (v) willful and material misrepresentation or concealment on ~~other indebtedness~~any written reports submitted to the Company or its direct or indirect subsidiaries; (vi) material breach of ~~our subsidiaries, defaults related~~the Employment Agreement; (vii) failure to ~~judgments~~follow or comply with the reasonable, material and lawful written directives of the Board; or (vii) conduct constituting his material breach of the Company’s then current code of conduct or similar written policy.

For purposes of the Employment Agreement, Mr. Willsher will have “good reason” to terminate his employment with the Company upon the occurrence of any of the following without his written consent: (i) a ~~Change~~relocation of his principal work location to a location more than 40 miles from its then current location; (ii) a reduction in ~~Control (as defined~~his then current base salary or Target Bonus, or both; (iii) a material breach of any provision of the Employment Agreement by the Company; or (iv) any material reduction in his title, authority, duties, responsibilities or reporting relationship from those in effect as of the Effective Date, except to the extent such reduction occurs in connection with his termination of employment for “cause” or due to his death or “disability”.

The Employment Agreement provides for a Code Section 280G “best-net” cutback, which would cause an automatic reduction in any payments or benefits Mr. Willsher would receive which constitute parachute payments within the meaning of Code Section 280G, in the ~~New Credit Agreement).~~event such reduction would result in Mr. Willsher receiving greater payments and benefits on an after-tax basis.

The ~~Company’s obligations under~~Employment Agreement subjects Mr. Willsher to employment term and 12-month post-employment non-competition, non-solicitation and non-interference restrictive covenants, as well as assignment of invention, perpetual non-disparagement and employment term and post-employment confidentiality covenants.

Mr. Smiley’s Employment Agreement provides Mr. Smiley with an initial base salary of $330,000 per year; an annual bonus opportunity (targeted at 70% of his annual base salary); 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) includedpotential to receive long-term incentive compensation awards as determined in the ~~determination~~Board’s discretion; the right to participate in the benefit plans, programs and arrangements available to the Company’s other senior executives generally, subject to the terms and conditions of such plans, programs and arrangements; and reimbursement for his business expenses incurred during the ~~borrowing base. OLLC and our other subsidiaries entered into a Pledge and Security Agreement in favor~~employment term. The remaining terms of ~~the Agent for the secured parties, pursuant to which OLLC’s obligations under the New Credit~~Mr. Smiley’s Employment Agreement are ~~secured by a first priority security interest~~substantially similar to Mr. Willsher’s Employment Agreement discussed above.

Mr. Willis’ Employment Agreement provides Mr. Willis with an initial base salary of $350,000 per year; an annual bonus opportunity (targeted at 65% of his annual base salary); the potential to receive long-term incentive compensation awards as determined in ~~substantially all~~the Board’s discretion; the right to participate in the benefit plans, programs and arrangements available to the Company’s other senior executives generally, subject to the terms and conditions of ~~our assets (subject to permitted liens). Additionally,~~such plans, programs and arrangements; and reimbursement for his business expenses incurred during the ~~Company entered into a Non-Recourse Pledge Agreement in favor~~employment term. The remaining terms of ~~the Agent for the secured parties, pursuant to which OLLC’s obligations under the New Credit~~Mr. Willis’ Employment Agreement are ~~secured by a pledge and security interest of 100% of the equity interests held by the Company in Amplify Acquisitionco, Inc.~~substantially similar to Mr. Willsher’s Employment Agreement discussed above.

The foregoing description of the ~~New Credit Agreement does not purport to be complete~~Employment Agreements for each of Messrs. Willsher, Smiley and isWillis are qualified in ~~its~~their entirety by reference to the ~~New Credit Agreement,~~Employment Agreements, which isare attached as Exhibits 10.1, 10.2 and 10.3 to this quarterly ~~report as Exhibit 10.2 and is incorporated by reference herein.~~report.

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 ☐


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
None	None	None

		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)~~March 31, 2019 and December 31, ~~2017~~2018 ~~(Successor Period)~~	7
	Unaudited Condensed Statements of Consolidated Operations for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2019 and 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~~Three Months Ended ~~September 30,~~March 31, 2019 and 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)~~	109
	Unaudited Condensed Statements of Consolidated Equity for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2019 and 2018 ~~(Successor Period)~~	1110
	Notes to Unaudited Condensed Consolidated Financial Statements
	Note 1 – Organization and Basis of Presentation	1211
	Note 2 – Summary of Significant Accounting Policies	1411
	Note 3 – Revenue	1512
	Note 4 – Acquisitions and Divestitures	1713
	Note 5 – Fair Value Measurements of Financial Instruments	1713
	Note 6 – Risk Management and Derivative Instruments	1915
	Note 7 – Asset Retirement Obligations	2017
	Note 8 – Long-term Debt	2118
	Note 9 – Equity (Deficit)	2318
	Note 10 – Earnings per ~~Share/Unit~~Share	2319
	Note 11 – Long-Term Incentive Plans	2419
	Note 12 – Leases	21
	Note 13 -Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Statements of Consolidated Cash Flows	27
	~~Note 13 – Related Party Transactions~~	2823
	Note 14 – ~~Commitments and Contingencies~~Related Party Transactions	2823
	Note 15 – ~~Income Taxes~~Commitments and Contingencies	2924
	Note 16 – Income Taxes	24
	Note 17 – Subsequent Events	2924

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3026
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4033
Item 4.	Controls and Procedures	4134

PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	4235
Item 1A.	Risk Factors	4235
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4237
Item 3.	Defaults Upon Senior Securities	4237
Item 4.	Mine Safety Disclosures	4237
Item 5.	Other Information	4237
Item 6.	Exhibits	4338

Signatures		4540

	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

	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 Three Months Ended
	Statements of	March 31,
	Operations Location	2019			2018
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	32,487		$	10,456
Interest rate derivatives	Interest expense, net		(94	)		—

	Common
	Shares
Balance, December 31, ~~2017 (Successor)~~2018		~~25,000,000~~22,181,881
Issuance of common stock		—
Restricted stock units vested		~~129,737~~287,658
Repurchase of common shares		(~~56,881~~88,508	)
Common stock repurchased and retired under share repurchase program		(122,581	)
Balance, ~~September 30, 2018 (Successor)~~March 31, 2019		~~25,072,856~~22,258,450

	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

	Office lease		Leased vehicles and office equipment			Total
Remaining 2019	$	1,533	$	388		$	1,921
2020		1,561		357			1,918
2021		1,320		219			1,539
2022 and thereafter		—		—			—
Total lease payments	$	4,414	$	964		$	5,378
Less: interest	$	319	$	48		$	367
Present value of lease liabilities	$	4,095	$	916	��	$	5,011

			Payment or Settlement Due by Period
Operating leases	Total		2019		2020		2021		2022		2023		Thereafter
Operating leases	$	11,846	$	5,893	$	2,072	$	2,109	$	337	$	205	$	1,230

	March 31,
	2019
Weighted average remaining lease term (years):
Corporate office	2.32
Vehicles		0.40
Office equipment		0.12
Weighted average discount rate:
Corporate office		4.12	%
Vehicles		0.48	%
Office equipment		0.21	%

Exhibit Number		Description
2.1	—	~~Second Amended Joint~~Agreement and Plan of ~~Reorganization of Memorial Production Partners LP~~Merger, dated May 5, 2019, by and ~~its affiliated Debtors, dated April 13, 2017~~among Amplify Energy Corp., Midstates Petroleum Company, Inc. and Midstates Holdings, Inc. (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)~~May 6, 2019).

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).

Exhibit Number		Description
10.1*	—	Employment Agreement, dated ~~July 30, 2018,~~May 3, 2019, by and between Amplify Energy Corp. and ~~Denise DuBard.~~Martyn Willsher.

10.2*	—	Employment Agreement, dated May 3, 2019, by and between Amplify Energy Corp. and Richard P. Smiley.

10.3*	—	Employment Agreement, dated May 3, 2019, by and between Amplify Energy Corp. and Eric M. Willis.

10.4	—	First Amendment to Credit Agreement, dated ~~as of November 2, 2018,~~May 5, 2019, by and among Amplify Energy Operating LLC, Amplify Acquisitionco Inc., ~~as parent,~~Amplify Energy Corp., the guarantors party thereto, lenders party thereto and Bank of Montreal, as administrative agent ~~and an L/C issuer, and~~(incorporated by reference to Exhibit 10.1 of the ~~other lenders and agents from time to time party thereto.~~Company’s Current Report on Form 8-K (File No. 001-35364) filed on May 6, 2019).

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~~May 9, 2019	By:	/s/ Martyn Willsher
	Name:	Martyn Willsher
	Title:	Senior Vice President and Chief Financial Officer


Date: ~~November 7, 2018~~May 9, 2019	By:	/s/ Denise DuBard
	Name:	Denise DuBard
	Title:	Vice President and Chief Accounting Officer