UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form ~~10-Q~~10–Q

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

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

For the quarterly period ended ~~September~~June 30, ~~2017~~2020

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

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

For the transition period from to .

Commission File Number: 001-35512

~~MIDSTATES PETROLEUM COMPANY, INC.~~Amplify Energy Corp.

(Exact name of registrant as specified in its charter)

Delaware		82-1326219
(State or other jurisdiction of incorporation or organization)		~~45-3691816~~ (I.R.S. Employer Identification No.)

500 Dallas Street, Suite 1700, Houston, TX		77002
~~321 South Boston Avenue, Suite 1000~~ ~~Tulsa, Oklahoma~~ (Address of principal executive offices)		~~74103~~ (Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically, ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes x☑ No o

☐

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

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

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

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

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

~~The number of shares outstanding of our stock at November 9, 2017 is shown below:~~Securities Registered Pursuant to Section 12(b):


~~Class~~Title of each class	Trading Symbol(s)	~~Number~~Name of ~~shares outstanding~~each exchange on which registered
Common Stock	AMPY	NYSE

As of July 31, 2020, the registrant had 37,621,684 outstanding shares of common stock, $0.01 par value outstanding.

AMPLIFY ENERGY CORP.

Table of Contents

~~25,173,346~~

~~DOCUMENTS INCORPORATED BY REFERENCE~~

~~None.~~

~~Table of Contents~~

~~MIDSTATES PETROLEUM COMPANY, INC.~~

~~QUARTERLY REPORT ON~~

~~FORM 10-Q~~

~~FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2017~~

~~TABLE OF CONTENTS~~

		Page

~~Glossary of Oil and Natural Gas Terms~~	3

		~~PART I — FINANCIAL INFORMATION~~Glossary of Oil and Natural Gas Terms		1
		Names of Entities		4
		Cautionary Note Regarding Forward-Looking Statements		5

PART I—FINANCIAL INFORMATION
Item 1. ~~Financial Statements~~
~~Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016 (unaudited)~~Financial Statements	4
~~Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 (Successor) and 2016 (Predecessor) (unaudited)~~	5
~~Condensed Consolidated Statements of Changes in Stockholders’ Equity/(Deficit) for the Nine Months Ended September 30, 2017 (Successor) and 2016 (Predecessor) (unaudited)~~	6
~~Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 (Successor) and 2016 (Predecessor) (unaudited)~~	7

~~Notes to the~~ Unaudited Condensed Consolidated ~~Financial Statements~~Balance Sheets as of June 30, 2020 and December 31, 2019		8
		Unaudited Condensed Statements of Consolidated Operations for the Three and Six Months Ended June 30, 2020 and 2019		9
		Unaudited Condensed Statements of Consolidated Cash Flows for the Six Months Ended June 30, 2020 and 2019		10
		Unaudited Condensed Statements of Consolidated Equity for the Three and Six Months Ended June 30, 2020 and 2019		11
		Notes to Unaudited Condensed Consolidated Financial Statements		12
		Note 1 – Organization and Basis of Presentation		12
		Note 2 – Summary of Significant Accounting Policies		14
		Note 3 – Revenue		15
		Note 4 – Acquisitions and Divestitures		15
		Note 5 – Fair Value Measurements of Financial Instruments		16
		Note 6 – Risk Management and Derivative Instruments		18
		Note 7 – Asset Retirement Obligations		20
		Note 8 – Long-term Debt		21
		Note 9 – Equity (Deficit)		22
		Note 10 – Earnings per Share		23
		Note 11 – Long-Term Incentive Plans		23
		Note 12 – Leases		25
		Note 13 -Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Statements of Consolidated Cash Flows		26
		Note 14 – Related Party Transactions		27
		Note 15 – Commitments and Contingencies		27
		Note 16 – Income Taxes		28

Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
	29
Item 3.		Quantitative and Qualitative Disclosures About Market Risk	36

~~Item 4. Controls and Procedures~~	37
Item 4.
~~PART II — OTHER INFORMATION~~Controls and Procedures

~~Item 1. Legal Proceedings~~	38

~~Item 1A. Risk Factors~~PART II—OTHER INFORMATION			38

Item 1.		Legal Proceedings		39
Item 1A.		Risk Factors		39
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds	38	40
Item 3.		Defaults Upon Senior Securities		40
Item 4.		Mine Safety Disclosures		40
Item 5.		Other Information		40
Item 6.		Exhibits		40

~~Item 3. Defaults upon Senior Securities~~	38

~~Item 4. Mine Safety Disclosures~~Signatures			38

~~Item 5. Other Information~~	38

~~Item 6. Exhibits~~	38

~~EXHIBIT INDEX~~	39

~~SIGNATURES~~	4142

GLOSSARY OF OIL AND NATURAL GAS TERMS

Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

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

Bbl/d: One Bbl per day.

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

Boe: One barrel ~~of oil.~~

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

~~Completion:~~ ~~The process~~calculated by converting natural gas to oil equivalent barrels at a ratio of ~~treating a drilled well followed by the installation of permanent equipment for the production~~six Mcf of natural gas ~~or oil, or in~~to one Bbl of oil.

BOEM: Bureau of Ocean Energy Management.

Btu: One British thermal unit, the ~~case~~quantity of heat required to raise the temperature of a ~~dry hole,~~one-pound mass of water by one degree Fahrenheit.

Development Project: A development project is the ~~reporting of abandonment~~means by which petroleum resources are brought to the ~~appropriate agency.~~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:~~Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production ~~do not~~would exceed production expenses and taxes.

~~Exploratory well:~~ ~~A well drilled~~Economically Producible: The term economically producible, as it relates to ~~find~~ a ~~new field~~resource, means a resource which generates revenue that exceeds, or is reasonably expected to ~~find a new reservoir in a field previously found to be productive~~exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

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

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand barrels of oil ~~in another reservoir.~~equivalent.

MBoe/d: One thousand barrels of oil equivalent per day.

MMBoe: One million barrels of oil equivalent.

Mcf: One thousand cubic feet of natural gas.

~~MMBtu:~~Mcf/d: One Mcf per day.

MMBtu: One million ~~British thermal units.~~Btu.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

MMcfe/d: One MMcfe per day.

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

NGLs: The ~~percentage~~combination of ~~total acres an owner has out~~ethane, propane, butane and natural gasolines that, when removed from natural gas, become liquid under various levels of ~~a particular number of acres, or a specified tract.~~higher pressure and lower temperature.

~~NYMEX:~~ ~~The~~NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

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

OPIS: Oil Price Information Service.

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 ~~reserves:~~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—~~producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government ~~regulations—~~regulations, prior to the time at which contracts providing the right to ~~drill or~~ operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including ~~but not limited to,~~ fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the ~~12-month~~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.

~~Reasonable certainty:~~ ~~A high degree~~Reliable Technology: Reliable technology is a grouping of ~~confidence.~~

~~Recompletion:~~ ~~The process of re-entering an existing wellbore~~one or more technologies (including computational methods) that ~~is either producing~~has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or ~~not producing and completing new reservoirs~~ in an ~~attempt to establish, re-establishing, or increase existing production.~~analogous formation.

~~Reserves:~~ ~~Estimated~~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:~~Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other ~~reservoirs.~~reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

Workover: Operations on a producing well to restore or increase production.

WTI: West Texas Intermediate.

~~Spud or Spudding:~~ ~~The commencement of drilling operations of a new well.~~NAMES OF ENTITIES

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

•	“Amplify Energy,” “Company,” “we,” “our,” “us” or like terms refers to Amplify Energy Corp. (f/k/a Midstates Petroleum Company, Inc.) individually and collectively with its subsidiaries, as the context requires;

•	“Legacy Amplify” refers to Amplify Energy Holdings LLC (f/k/a Amplify Energy Corp.), the successor reporting company of Memorial Production Partners LP;

•	“Midstates” refers to Midstates Petroleum Company, Inc., which, on the effective date of the Merger (as defined below), changed its name to “Amplify Energy Corp.”; and

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

~~Wellbore:~~ ~~The hole drilled~~CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and section 21E of the Securities Exchange Act of 1934, as amended, that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

•

business strategies;

•

acquisition and disposition strategy;

•

cash flows and liquidity;

•

financial strategy;

•

ability to replace the reserves we produce through drilling;

•

drilling locations;

•

oil and natural gas reserves;

•

technology;

•

realized oil, natural gas and NGL prices;

•

production volumes;

•

lease operating expense;

•

gathering, processing, and transportation;

•

general and administrative expense;

•

future operating results;

•

ability to procure drilling and production equipment;

•

ability to procure oil field labor;

•

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

•

ability to access capital markets;

•

marketing of oil, natural gas and NGLs;

•

risks relating to transportation and storage capacity constraints;

•

risks relating to production curtailment;

•

a sustained decrease or further decline in the demand for oil and natural gas;

•

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

•

the occurrence or threat of epidemic or pandemic diseases, such as the recent outbreak of a novel strain of coronavirus (“COVID-19”), or any government response to such occurrence or threat;

•

expectations regarding general economic conditions;

•

competition in the oil and natural gas industry;

•

effectiveness of risk management activities;

•

environmental liabilities;

•

counterparty credit risk;

•

expectations regarding governmental regulation and taxation;

•

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

•

plans, objectives, expectations and intentions.

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 ~~bit~~negative of such terms or other comparable terminology. These statements address activities, events or developments that ~~is equipped~~we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for ~~oil~~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 ~~gas production on a completed well. Also called well~~financial condition to differ materially from those expressed or ~~borehole.~~

~~Working interest:~~ ~~The right granted~~implied by forward-looking statements include, but are not limited to, the ~~lessee~~following risks and uncertainties:

•

our results of evaluation and implementation of strategic alternatives;

•

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

•

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

•

our ability to satisfy debt obligations;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

potential difficulties in the marketing of oil and natural gas;

•

changes to the financial condition of counterparties;

•

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

•

competition in the oil and natural gas industry;

•

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

•

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

•

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

•

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

•

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

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 Amplify’s Annual Report on Form 10-K for the year ended December 31, 2019 filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2020 (“Amplify Form 10-K”). 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 ~~property~~result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to ~~explore for and to produce and own oil, natural gas,~~us or ~~other minerals. The working interest owners bear the exploration, development, and operating costs~~persons acting on ~~a cash, penalty, or carried basis.~~our behalf.

PART ~~I —~~ I—FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS.

AMPLIFY ENERGY CORP.

~~MIDSTATES PETROLEUM COMPANY, INC.~~

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

~~(Unaudited)~~

(In thousands, except ~~share amounts)~~outstanding shares)

September 30, 2017

December 31, 2016

ASSETS

CURRENT ASSETS:

Cash and cash equivalents

$
76,548

$
76,838

Accounts receivable:

Oil and gas sales

29,776

36,988

Joint interest billing

3,193

4,281

Other

630

2,456

Commodity derivative contracts

2,896

—

Other current assets

1,821

3,326

Total current assets

114,864

123,889

PROPERTY AND EQUIPMENT:

Oil and gas properties, on the basis of full-cost accounting

Proved properties

709,647

573,150

Unproved properties not being amortized

26,178

65,080

Other property and equipment

6,543

6,339

Less accumulated depreciation, depletion and amortization

(59,349
)
(12,974
)
Net property and equipment

683,019

631,595

OTHER NONCURRENT ASSETS

7,156

5,455

TOTAL

$
805,039

$
760,939

LIABILITIES AND EQUITY

CURRENT LIABILITIES:

Accounts payable

$
9,480

$
2,521

Accrued liabilities

46,987

53,731

Total current liabilities

56,467

56,252

LONG-TERM LIABILITIES:

Asset retirement obligations

14,039

14,200

Commodity derivative contracts

278

—

Long-term debt

128,059

128,059

Other long-term liabilities

599

614

Total long-term liabilities

142,975

142,873

COMMITMENTS AND CONTINGENCIES (Note 14)

STOCKHOLDERS’ EQUITY:

Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at September 30, 2017 and December 31, 2016

—

—

Warrants, 6,625,554 warrants outstanding at September 30, 2017 and December 31, 2016

37,329

37,329

Common stock, $0.01 par value, 250,000,000 shares authorized; 25,098,834 shares issued and 25,065,425 shares outstanding at September 30, 2017 and 24,994,867 shares issued and outstanding at December 31, 2016

251

250

Treasury stock

(626
)
—

Additional paid-in-capital

522,823

514,305

Retained earnings

45,820

9,930

Total stockholders’ equity

605,597

561,814

TOTAL

$
805,039

$
760,939

	June 30,			December 31,
	2020			2019
ASSETS
Current assets:
Cash and cash equivalents	$	13,202		$	—
Restricted cash		—			325
Accounts receivable, net		27,132			33,145
Short-term derivative instruments		32,216			5,879
Prepaid expenses and other current assets		12,223			13,238
Total current assets		84,773			52,587
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		767,823			797,005
Support equipment and facilities		142,437			140,023
Other		8,765			8,045
Accumulated depreciation, depletion and impairment		(570,237	)		(141,350	)
Property and equipment, net		348,788			803,723
Long-term derivative instruments		9,134			6,364
Restricted investments		4,622			4,622
Operating lease - long term right-of-use asset		3,528			4,406
Other long-term assets		2,838			5,837
Total assets	$	453,683		$	877,539

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	5,630		$	8,310
Revenues payable		22,542			29,167
Accrued liabilities (see Note 13)		17,837			23,358
Short-term derivative instruments		785			253
Current portion of long-term debt (see Note 8)		20,000			—
Total current liabilities		66,794			61,088
Long-term debt (see Note 8)		265,516			285,000
Asset retirement obligations		93,568			90,466
Long-term derivative instruments		1,833			305
Operating lease liability		1,350			2,720
Other long-term liabilities		3,367			3,753
Total liabilities		432,428			443,332
Commitments and contingencies (see Note 15)
Stockholders' equity:
Preferred stock, $0.01 par value: 50,000,000 shares authorized; 0 shares issued and outstanding at June 30, 2020 and December 31, 2019, respectively		—			—
Warrants, 2,173,913 and 9,153,522 warrants issued and outstanding at June 30, 2020 and December 31, 2019, respectively		4,788			4,790
Common stock, $0.01 par value: 250,000,000 shares authorized; 37,612,914 and 37,566,540 shares issued and outstanding at June 30, 2020 and December 31, 2019, respectively		209			209
Additional paid-in capital		423,770			424,399
Accumulated earnings		(407,512	)		4,809
Total stockholders' equity		21,255			434,207
Total liabilities and equity	$	453,683		$	877,539

~~The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.~~See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

AMPLIFY ENERGY CORP.

~~MIDSTATES PETROLEUM COMPANY, INC.~~

UNAUDITED CONDENSED ~~CONSOLIDATED~~ STATEMENTS OF CONSOLIDATED OPERATIONS

~~(Unaudited)~~

(In thousands, except per share amounts)

Successor

Predecessor

Successor

Predecessor

For the Three
Months Ended

For the Three
Months Ended

For the Nine
Months Ended

For the Nine
Months Ended

September 30, 2017

September 30, 2016

September 30, 2017

September 30, 2016

REVENUES:

Oil sales

$
27,190

$
35,584

$
85,497

$
104,832

Natural gas liquid sales

10,656

8,939

31,580

25,073

Natural gas sales

13,970

17,676

46,321

44,486

Gains (losses) on commodity derivative contracts—net

(3,591
)

—

8,767

—

Other

1,490

1,994

3,244

4,322

Total revenues

49,715

64,193

175,409

178,713

EXPENSES:

Lease operating and workover

15,653

17,650

48,064

49,520

Gathering and transportation

3,699

4,296

11,027

13,428

Severance and other taxes

2,352

1,788

6,168

4,776

Asset retirement accretion

274

452

833

1,316

Depreciation, depletion, and amortization

15,170

15,756

46,471

59,229

Impairment in carrying value of oil and gas properties

—

33,887

—

224,584

General and administrative

7,255

3,308

23,102

19,093

Debt restructuring costs and advisory fees

—

—

—

7,589

Total expenses

44,403

77,137

135,665

379,535

OPERATING INCOME (LOSS)

5,312

(12,944
)
39,744

(200,822
)
OTHER EXPENSE:

Interest income

—

—

—

81

Interest expense—net of amounts capitalized (excludes interest expense of $47.6 million and $79.3 million on senior and secured notes subject to compromise for the three and nine months ended September 30, 2016, respectively)

(1,649
)

(2,668
)
(3,854
)

(65,719
)
Reorganization items, net

—

(22,772
)
—

57,764

Total other expense

(1,649
)

(25,440
)
(3,854
)

(7,874
)
INCOME (LOSS) BEFORE TAXES

3,663

(38,384
)
35,890

(208,696
)
Income tax expense

—

—

—

—

NET INCOME (LOSS)

$
3,663

$
(38,384
)
$
35,890

$
(208,696
)
Successor participating securities—non-vested restricted stock

(82
)

—

(932
)

—

Predecessor participating securities—non-vested restricted stock

—

—

—

—

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS

$
3,581

$
(38,384
)
$
34,958

$
(208,696
)
Basic and diluted net income (loss) per share attributable to common shareholders

$
0.14

$
(3.60
)
$
1.39

$
(19.61
)
Basic and diluted weighted average number of common shares outstanding (Note 12)

25,116

10,657

25,074

10,644

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
Revenues:
Oil and natural gas sales	$	34,888		$	59,485		$	92,675		$	124,552
Other revenues		283			47			632			135
Total revenues		35,171			59,532			93,307			124,687

Costs and expenses:
Lease operating expense		27,828			26,292			63,551			55,202
Gathering, processing and transportation		4,689			4,391			9,742			9,048
Exploration		3			6			19			21
Taxes other than income		2,195			3,464			6,181			7,873
Depreciation, depletion and amortization		7,623			12,913			23,179			24,079
Impairment expense		—			—			455,031			—
General and administrative expense		6,755			10,566			15,108			19,874
Accretion of asset retirement obligations		1,539			1,332			3,052			2,643
(Gain) loss on commodity derivative instruments		19,165			(22,993	)		(88,548	)		9,494
Other, net		—			34			—			177
Total costs and expenses		69,797			36,005			487,315			128,411
Operating income (loss)		(34,626	)		23,527			(394,008	)		(3,724	)
Other income (expense):
Interest expense, net		(6,209	)		(4,422	)		(13,856	)		(8,511	)
Other income (expense)		(250	)		—			(234	)		—
Total other income (expense)		(6,459	)		(4,422	)		(14,090	)		(8,511	)
Income (loss) before reorganization items, net and income taxes		(41,085	)		19,105			(408,098	)		(12,235	)
Reorganization items, net		(166	)		(464	)		(352	)		(651	)
Income tax benefit (expense)		(85	)		—			(85	)		50
Net income (loss)		(41,336	)		18,641			(408,535	)		(12,836	)
Net (income) loss allocated to participating restricted stockholders		—			(728	)		—			—
Net income (loss) attributable to common stockholders	$	(41,336	)	$	17,913		$	(408,535	)	$	(12,836	)

Earnings per share: (See Note 10)
Basic and diluted earnings per share	$	(1.10	)	$	0.80		$	(10.87	)	$	(0.58	)
Weighted average common shares outstanding:
Basic and diluted		37,595			22,267			37,582			22,223

~~The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.~~

~~MIDSTATES PETROLEUM COMPANY, INC.~~

~~CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY/(DEFICIT)~~

~~(Unaudited)~~

~~(In thousands)~~

Series A
Preferred
Stock

Common
Stock

Warrants

Treasury
Stock

Additional
Paid-in-Capital

Retained
Earnings

Total
Stockholders’
Equity

Balance as of December 31, 2016 (Successor)

$
—

$
250

$
37,329

$
—

$
514,305

$
9,930

$
561,814

Share-based compensation

—

1

—

—

8,518

—

8,519

Acquisition of treasury stock

—

—

—

(626
)
—

—

(626
)
Net income

—

—

—

—

—

35,890

35,890

Balance as of September 30, 2017 (Successor)

$
—

$
251

$
37,329

$
(626
)
$
522,823

$
45,820

$
605,597

Series A
Preferred
Stock

Common
Stock

Warrants

Treasury
Stock

Additional
Paid-in-Capital

Retained
Deficit

Total
Stockholders’
Deficit

Balance as of December 31, 2015 (Predecessor)

$
—

$
110

$
—

$
(3,081
)
$
888,247

$
(2,211,342
)
$
(1,326,066
)
Share-based compensation

—

(1
)
—

—

1,726

—

1,725

Acquisition of treasury stock

—

—

—

(53
)
—

—

(53
)
Net loss

—

—

—

—

—

(208,696
)
(208,696
)
Balance as of September 30, 2016 (Predecessor)

$
—

$
109

$
—

$
(3,134
)
$
889,973

$
(2,420,038
)
$
(1,533,090
)

~~The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.~~

~~MIDSTATES PETROLEUM COMPANY, INC.~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

~~(In thousands)~~

Successor

Predecessor

For the Nine Months
Ended

For the Nine Months
Ended

September 30, 2017

September 30, 2016

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income (loss)

$
35,890

$
(208,696
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Gains on commodity derivative contracts—net

(8,767
)

—

Net cash received for commodity derivative contracts not designated as hedging instruments

6,149

—

Asset retirement accretion

833

1,316

Depreciation, depletion, and amortization

46,471

59,229

Impairment in carrying value of oil and gas properties

—

224,584

Share-based compensation, net of amounts capitalized to oil and gas properties

7,102

1,275

Amortization of deferred financing costs

277

4,495

Paid-in-kind interest expense

—

3,531

Amortization of deferred gain on debt restructuring

—

(8,246
)
Operating lease abandonment

—

1,574

Noncash reorganization items

—

(70,489
)
Change in operating assets and liabilities:

Accounts receivable—oil and gas sales

4,929

(311
)
Accounts receivable—JIB and other

2,641

21,411

Other current and noncurrent assets

(98
)

(5,572
)
Accounts payable

1,392

870

Accrued liabilities

(7,381
)

54,520

Other

(121
)

(1,247
)
Net cash provided by operating activities

$
89,317

$
78,244

CASH FLOWS FROM INVESTING ACTIVITIES:

Investment in property and equipment

$
(92,841
)

$
(129,072
)
Proceeds from the sale of oil and gas equipment and properties

4,235

—

Net cash used in investing activities

$
(88,606
)

$
(129,072
)
CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from revolving credit facility

—

249,384

Deferred financing costs

(375
)

—

Acquisition of treasury stock

(626
)

(53
)
Net cash (used in) provided by financing activities

$
(1,001
)

$
249,331

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS

$
(290
)

$
198,503

Cash and cash equivalents, beginning of period

$
76,838

$
81,093

Cash and cash equivalents, end of period

$
76,548

$
279,596

SUPPLEMENTAL INFORMATION:

Non-cash transactions — investments in property and equipment accrued — not paid

$
19,865

$
12,238

Cash paid for interest, net of capitalized interest of $2.1 million for the nine months ended September 30, 2017 (no capitalized interest for the nine months ended September 30, 2016)

$
3,708

$
5,821

Cash paid for reorganization items

$
—

$
12,725

~~The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.~~

~~MIDSTATES PETROLEUM COMPANY, INC.~~

See Accompanying Notes to Unaudited Condensed Consolidated Financial ~~Statements~~Statements.

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(In thousands)

	For the Six Months Ended
	June 30,
	2020			2019
Cash flows from operating activities:
Net income (loss)	$	(408,535	)	$	(12,836	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		23,179			24,079
Impairment expense		455,031			—
(Gain) loss on derivative instruments		(84,494	)		10,028
Cash settlements (paid) received on expired derivative instruments		39,471			(1,863	)
Cash settlements (paid) received on terminated derivative instruments		17,977			—
Bad debt expense		252			101
Amortization and write-off of deferred financing costs		2,999			574
Accretion of asset retirement obligations		3,052			2,643
Share-based compensation (see Note 11)		(632	)		2,922
Settlement of asset retirement obligations		—			(205	)
Changes in operating assets and liabilities:
Accounts receivable		5,762			6,576
Prepaid expenses and other assets		659			(2,630	)
Payables and accrued liabilities		(11,345	)		3,823
Other		(387	)		87
Net cash provided by operating activities		42,989			33,299
Cash flows from investing activities:
Additions to oil and gas properties		(26,123	)		(33,232	)
Additions to other property and equipment		(719	)		(205	)
Additions to restricted investments		—			(138	)
Withdrawals of restricted investments		—			90,000
Net cash provided by (used in) investing activities		(26,842	)		56,425
Cash flows from financing activities:
Advances on revolving credit facilities		25,000			—
Payments on revolving credit facilities		(30,000	)		(119,000	)
Proceeds from the paycheck protection program		5,516			—
Deferred financing costs		—			(169	)
Dividends to stockholders		(3,786	)		—
Common stock repurchased and retired under the share repurchase program		—			(1,251	)
Costs incurred in conjunction with tender offer		—			(107	)
Restricted units returned to plan		(35	)		(199	)
Other		35			��
Net cash provided by (used in) financing activities		(3,270	)		(120,726	)
Net change in cash, cash equivalents and restricted cash		12,877			(31,002	)
Cash, cash equivalents and restricted cash, beginning of period		325			50,029
Cash, cash equivalents and restricted cash, end of period	$	13,202		$	19,027

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(In thousands)

	Stockholders' Equity
	Common Stock		Warrants			Additional Paid-in Capital			Accumulated Earnings (Deficit)			Total
Balance at December 31, 2019	$	209	$	4,790		$	424,399		$	4,809		$	434,207
Net loss		—		—			—			(367,199	)		(367,199	)
Share-based compensation expense		—		—			(1,112	)		—			(1,112	)
Restricted shares repurchased		—		—			(14	)		—			(14	)
Dividends		—		—			—			(3,786	)		(3,786	)
Balance at March 31, 2020		209		4,790			423,273			(366,176	)		62,096
Net income (loss)		—		—			—			(41,336	)		(41,336	)
Share-based compensation expense		—		—			480			—			480
Expiration of warrants		—		(2	)		2			—			—
Restricted shares repurchased		—		—			(20	)		—			(20	)
Other		—		—			35			—			35
Balance at June 30, 2020	$	209	$	4,788		$	423,770		$	(407,512	)	$	21,255

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 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
)
Balance at March 31, 2019

3

4,788

356,288

24,418

385,497

Net income (loss)

—

—

—

18,641

18,641

Share-based compensation expense

—

—

1,479

—

1,479

Common stock repurchased and retired under the share repurchase program

—

—

(331
)

—

(331
)
Restricted shares repurchased

—

—

(199
)

—

(199
)
Balance at June 30, 2019
$
3

$
4,788

$
357,237

$
43,059

$
405,087

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and ~~Business~~Basis of Presentation

General

On August 6, 2019, Midstates Petroleum Company, Inc. ~~engages~~, a Delaware corporation (“Midstates”), completed its business combination (the “Merger”) with Amplify Energy Corp. (“Legacy Amplify”) in accordance with the terms of that certain Agreement and Plan of Merger, dated May 5, 2019 (the “Merger Agreement”), by and among Midstates, Legacy Amplify and Midstates Holdings, Inc., a Delaware corporation and direct, wholly owned subsidiary of Midstates (“Merger Sub”). Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates, and immediately following the Merger, Legacy Amplify merged with and into Alpha Mike Holdings LLC, a Delaware limited liability company and wholly owned subsidiary of Midstates (“LLC Sub”), with LLC Sub surviving as a wholly owned subsidiary of Midstates. On the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.” (the “Company”) and LLC Sub changed its name to “Amplify Energy Holdings LLC.”

For financial reporting purposes, the Merger represented a “reverse merger” and Legacy Amplify was deemed to be the accounting acquirer in the ~~business~~transaction. Legacy Amplify’s historical results of ~~exploring and drilling~~operations will replace Midstates’ historical results of operations for ~~and the production of, oil, natural gas liquids (“NGLs”) and natural gas in Oklahoma and Texas. Midstates Petroleum Company, Inc. was incorporated pursuant~~all periods prior to the ~~laws~~Merger and, for all periods following the Merger, the Company’s financial statements will reflect the results of operations of the ~~State~~combined company. Accordingly, the financial statements for the Company included in this Quarterly Report on Form 10-Q for periods prior to the Merger are not the same as Midstates prior reported filings with the SEC, which were derived from the operations of ~~Delaware on October 25, 2011~~Midstates. As a result, period-to-period comparisons of our operating results may not be meaningful. The results of any one quarter should not be relied upon as an indication of future performance.

When referring to ~~become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”). The terms “Company,” “we,” “us,” “our,” and similar terms~~Legacy Amplify, the intent is to refer to ~~Midstates Petroleum Company, Inc.~~Amplify Energy Corp. prior to the effective date of the Merger, and its ~~subsidiary.~~consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

~~The Company operates a significant portion~~We operate in 1 reportable segment engaged in the acquisition, development, exploitation and production of ~~its~~ oil and natural gas properties. ~~The Company’s~~Our management evaluates performance based on one reportable business segment as ~~all~~the economic environments are not different within the operation of ~~its operations~~our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Oklahoma, the ~~United States~~Rockies, federal waters offshore Southern California, East Texas / North Louisiana and ~~therefore, it maintains one cost center.~~

~~On April 30, 2016, the Company filed voluntary petitions for reorganization under Chapter 11~~South Texas. Most of ~~the United States Bankruptcy Code~~our oil and natural gas properties are located in ~~the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).~~large, mature oil and natural gas reservoirs. The Company’s ~~Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered under the case styled~~ ~~In re Midstates Petroleum Company, Inc., et al., Case No. 16-32237~~~~. On September 28, 2016, the Bankruptcy Court entered the~~ ~~Findings~~properties consist primarily of ~~Fact, Conclusions of Law,~~operated and ~~Order Confirming Debtors’ First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc.~~non-operated working interests in producing and ~~its Debtor Affiliate~~ ~~(the “Confirmation Order”), which approved~~undeveloped leasehold acreage and confirmed the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on the same date (the “Plan”). On October 21, 2016 (the “Effective Date”), the Company satisfied the conditions to effectiveness set forthworking interests in ~~the Confirmation Order and in the Plan, and, as a result, the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 Cases.~~identified producing wells.

~~2. Summary of Significant Accounting Policies~~

Basis of Presentation

~~These interim financial statements are unaudited and~~Our Unaudited Condensed Consolidated Financial Statements included herein have been prepared pursuant to the rules and ~~regulations~~guidelines of the ~~Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain~~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 ~~have been condensed or omitted from~~in these financial ~~statements. Accordingly, they do not include all of the~~statements are adequate, certain information and ~~notes required by~~footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) ~~for complete consolidated~~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 ~~should be read in conjunction~~events that are directly associated with the ~~audited consolidated financial statements~~reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and ~~notes thereto for the year ended December 31, 2016 included~~losses that were realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s ~~Annual Report on Form 10-K as filed with the SEC on March 30, 2017.~~

Unaudited Condensed Statements of Consolidated Operations.

All intercompany transactions and balances have been eliminated in ~~consolidation. In the opinion~~preparation of our consolidated financial statements.

Use of Estimates

The preparation of the ~~Company’s~~accompanying Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management ~~the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary~~ to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying unaudited condensed consolidated financial statements, management has made certainmake estimates and assumptions that affect the reported amounts inof assets and liabilities and disclosure of contingent assets and liabilities at the ~~unaudited condensed~~date of the consolidated financial statements and ~~disclosures~~the reported amounts of ~~contingencies.~~revenues and expenses during the reporting period. Actual results ~~may~~could differ from those estimates. ~~The results for interim periods~~

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Significant estimates include, but are not ~~necessarily indicative~~limited to, oil and natural gas reserves; depreciation, depletion, and amortization of ~~annual results.~~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.

Risk and Uncertainties

In ~~accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852,~~ ~~Reorganizations~~,March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the United States. The spread of COVID-19 has caused significant volatility in U.S. and international markets. There is significant uncertainty around the breadth and duration of business disruptions related to COVID-19, as well as its impact on the U.S. and international economies and, as such, the Company ~~adopted fresh start accounting upon emergence~~is unable to determine the extent of the impact caused by the COVID-19 pandemic to the Company’s operations.

The pandemic has lowered the demand for oil and natural gas which has led to low commodity prices. The reductions in commodity prices have resulted in lower levels of cash flow from operating activities. In addition, the ~~Chapter 11 Cases resulting~~borrowing base under our Revolving Credit Facility (as defined below) is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated oil, NGL and natural gas reserves which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Severely reduced commodity prices contributed to a reduction in our borrowing base during the ~~Company becoming a new entity~~Spring 2020 determination process, and continued low prices may adversely impact subsequent redeterminations. The reduction in commodity prices has directly led to an impairment of our oil and natural gas properties. There may be further impairments in future periods if commodity prices continue to decline.

In addition, oil prices severely declined following unsuccessful negotiations between members of Organization of the Petroleum Exporting Countries (“OPEC”) and certain nonmembers, including Russia, to implement production cuts in an effort to decrease the global oversupply and to rebalance supply and demand due to the ongoing COVID-19 pandemic. In April 2020, members of OPEC and Russia agreed to temporary production reductions, but uncertainty about whether such production cuts and/or the duration of such reductions will be sufficient to rebalance supply and demand remains and may continue for ~~financial reporting purposes. As~~the foreseeable future. We anticipate further market and commodity price volatility for the remainder of 2020 as a result of the ~~application~~events described above.

Notice of ~~fresh start accounting, as well as~~Non-Compliance with New York Stock Exchange (“NYSE”) Continued Listing Standards

On April 20, 2020, the ~~effects~~Company received written notification (the “Notice”) from the NYSE that the Company no longer satisfied the continued listing compliance standards set forth under Section 802.01C of the ~~implementation~~NYSE Listed Company Manual (“Section 802.01C”) because the average closing price of the ~~Plan,~~Company’s common stock was below $1.00 over a 30 consecutive trading-day period that ended April 17, 2020. Under the NYSE’s rules, the Company had six months following receipt of the Notice to regain compliance with the minimum share price requirement. The Company notified the NYSE of its intent to cure the deficiency and return to compliance with the NYSE’s continued listing requirements. The common stock symbol “AMPY” was assigned a “.BC” indicator by the NYSE to signify that the Company was not in compliance with the NYSE’s continued listing requirements.

On April 20, 2020, the NYSE made a rule filing with the SEC for relief from the $1.00 per share continued listing standard, which became immediately effective on April 21, 2020. The relief provided that the cure period was suspended until June 30, 2020 and recommenced on July 1, 2020. The Company’s cure period under the relief was extended to December 29, 2020.

On June 2, 2020, the Company received written notification from the NYSE that the Company regained compliance with the NYSE’s continued listing standards. The Company regained compliance after its average closing price for the 30 trading-day period ended May 29, 2020 and its closing price on May 29, 2020 both exceeded $1.00 per share. The “.BC” indicator has been removed from the Company’s common shares and the Company was removed from the NYSE list of non-compliant issuers.

Retirement of President, Chief Executive Officer and Director

On April 1, 2020, Mr. Kenneth Mariani notified the board of directors of the Company of his decision to retire. Mr. Mariani vacated his service as President and Chief Executive Officer of the Company and as a member of the board of directors, effective April 3, 2020. Mr. Mariani’s decision to retire stems solely from personal reasons and did not result from any disagreement with the Company, the Company’s management or the board of directors.

Appointment of Interim Chief Executive Officer

Effective upon Mr. Mariani’s retirement, Mr. Martyn Willsher was appointed the Company’s Interim Chief Executive Officer. Mr. Willsher continues to serve in his role as Senior Vice President and Chief Financial Officer of the Company.

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Departure of Director

On June 22, 2020, Scott L. Hoffman notified the Company of his intent to resign from the board of directors of the Company, effective June 23, 2020. Mr. Hoffman served as a member and Chairman of the Nominating and Governance Committee of the board of directors. There were no known disagreements between Mr. Hoffman and the Company which led to Mr. Hoffman’s resignation from the board of directors. On June 23, 2020, Christopher W. Hamm, a current member of the board of directors, was appointed to serve as a member and Chairman of the Nominating and Governance Committee of the board of directors.

Definitive Merger Agreement

On May 5, 2019, as discussed above, the Company entered into the Merger Agreement pursuant to which Legacy Amplify merged with a subsidiary of Midstates in an all-stock merger-of-equals. Under the terms of the Merger Agreement, Legacy Amplify stockholders received 0.933 shares of newly issued Company common stock for each share of Legacy Amplify common stock that they owned. The Merger closed on August 6, 2019.

Note 2. Summary of Significant Accounting Policies

Other than the accounting policies implemented in connection with the adoption of the current expected credit losses, there have been no changes to the Company’s significant accounting policies and estimates as described in the Company’s annual financial statements included in our Annual Report on Form 10-K.

Current Expected Credit Losses

In May 2019, the Financial Accounting Standard Board (the “FASB”) issued an accounting standard update to provide entities with an option to irrevocably elect the fair value option applied on an instrument-by-instrument basis for certain financial assets upon the adoption. The fair value option election does not apply to held-to-maturity debt securities. The Company adopted the guidance as of January 1, 2020. The Company has evaluated the impact of this guidance and concluded that the current and historical evaluation of estimated credit losses falls within the acceptable guidance.

The provisions of the standard were interpreted to relate only to the Company’s accounts receivable, net. Trade receivables relate to one common pool, revenue earned on the sale of oil, natural gas and natural gas liquids. The performance obligation is satisfied at a point in time and revenue is recognized and a trade receivable is recorded from the sale when production is delivered to, and title has transferred to, the purchaser. The majority of the Company’s purchasers have been large major companies in the industry with the wherewithal to pay.

The Company, as operator on most of our wells, also records receivables on billings to our joint interest owners who participate in the operating costs of the wells they have an interest in. Historically an allowance for doubtful accounts has been set up to recognize credit losses on joint interest billing (“JIB”) receivables based upon an aging analysis which is an appropriate method to estimate credit losses under the guidance. The Company will continue to assess the expected credit loss in the future as economic conditions change. Considering the recent drop in commodity prices we believe the majority of our revenue purchasers have the size and financial condition to currently meet their obligations. There could be added risk on the JIB accounts receivable as some wells could become uneconomic, with the revenue not enough to cover operating expenses billed, which could result in additional write-offs. The Company will continue to closely monitor trade receivables. Based upon the analysis performed there was no impact to beginning retained earnings upon the adoption of the guidance. The Company’s monitoring activities include timely account reconciliation and balances are written off when determined to be uncollectible. The Company considered the market conditions surrounding the COVID-19 pandemic and determined that the estimate of credit losses was not significantly impacted. The Company will continue to closely monitor trade receivables.

New Accounting Pronouncements

Reference Rate Reform. In March 2020, the FASB issued an accounting standard update which provides optional expedients and expectations for applying GAAP to contracts, hedging relationships, and other transactions to ease financial reporting burdens to the expected market transition from the London Interbank Offered Rate (“LIBOR”) or another reference rate to alternative reference rates. The amendments in this accounting standards update are effective beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. The Company is currently evaluating the impact this guidance may have on the Company’s consolidated financial statements on or after October 21, 2016, are not comparable with the consolidated financial statements prior to that date. References to “Successor Period” relate to the results of operations for the period January 1, 2017 through September 30, 2017 and references to “Predecessor Period” refer to the results of operations from January 1, 2016 through September 30, 2016.statements.

~~Recent Accounting Pronouncements~~14

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes – Simplifying the Accounting for Income Taxes. In ~~May 2014,~~December 2019, the FASB issued ~~Accounting Standards Update 2014-09,~~ ~~“Revenue~~an accounting standard update which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. This accounting standards update removes the following exceptions: (i) exception to the incremental approach for intraperiod tax allocation when there is a loss from ~~Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 provides guidance concerning~~continuing operations and income or a gain from other items; (ii) exception to the ~~recognition~~requirements to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment; (iii) exception to the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary; and ~~measurement of revenue from contracts with customers.~~(iv) exception to the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. The ~~objective of ASU 2014-09 is to increase the usefulness of information~~amendments in the ~~financial statements regarding the nature, timing~~accounting standards update also improve consistency and ~~uncertainty~~simplify other areas of ~~revenues. The Company has completed its review of contracts for each revenue stream identified within the Company’s business~~Topic 740 by clarifying and ~~is currently finalizing its conclusion on any changes in revenue recognition upon adoption of the revised~~amending existing guidance. Based on assessments to date, the Company believes ASU 2014-09 will impact the presentation of future revenues and expenses by including certain transportation and gathering costs, along with various other fees such as compression and marketing fees net within revenues. The inclusion of these costs within revenues will not impact the Company’s revenue recognition, its financial position, net income or cash flows. In addition, several industry interpretations are currently open for public comment. The Company cannot quantitatively assess the impact of ASU 2014-09 on its financial statements until final consensus is reached on these various industry matters. Once all pending industry interpretations are addressed, the Company will finalize its assessment of ASU 2014-09. The Company is in the process of evaluating the information technology and internal control changes that will be required for adoption based on the Company’s contract review process, but does not currently anticipate material impacts to either information technology or internal controls. However, this assessment is pending conclusion of various industry interpretations. The Company intends to apply the modified retrospective approach upon adoption of this standard on the effective date of January 1, 2018.

~~In February 2016, the FASB issued Accounting Standards Update 2016-02,~~ ~~“Leases (Topic 842)”~~ (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. The new ~~standard~~guidance is effective for fiscal years and interim period within those fiscal years, beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available.2020. The Company is incurrently evaluating the ~~initial evaluation and planning stages for ASU 2016-02 and does not expect to move beyond~~impact of this ~~stage until completion of its evaluation of ASU 2014-09.~~guidance on the Company's consolidated financial statements.

~~In July 2017,~~Other accounting standards that have been issued by the FASB ~~issued Accounting Standards Update 2017-11,~~ ~~“Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)”~~ (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260or other standards-setting bodies are not expected to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company does not believe the adoption of ASU 2017-11 will have a material impact on ~~its~~the Company’s financial position, results of operations orand cash flows.

Note 3. Revenue

Revenue from contracts with customers

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 June 30, 2020.

Disaggregation of Revenue

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

	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2020		2019		2020		2019
	(in thousands)
Revenues
Oil	$	22,963	$	41,685	$	64,814	$	81,742
NGLs		3,343		5,336		8,465		11,201
Natural gas		8,582		12,464		19,396		31,609
Oil and natural gas sales	$	34,888	$	59,485	$	92,675	$	124,552

Contract Balances

Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $19.3 million at June 30, 2020 and $31.9 million at December 31, 2019.

Note 4. Acquisitions and Divestitures

Acquisition and Divestiture Related Expenses

There were no material acquisition or divestitures during the three and six months ended June 30, 2020 and 2019, respectively.

Business Combination

Acquisitions qualifying as a business combination are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the condensed consolidated balance sheet at their fair values as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3.Merger

On May 5, 2019, Midstates, Legacy Amplify and Merger Sub entered into the Merger Agreement pursuant to which, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates. At the effective time of the Merger, each share of Legacy Amplify common stock issued and outstanding immediately prior to the effective time (other than excluded shares) were cancelled and converted into the right to receive 0.933 shares of Midstates common stock, par value $0.01 per share. On August 6, 2019, the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.”

Unaudited Pro Forma Financials

The following unaudited pro forma financial information for the three and six months ended June 30, 2019, is based on our historical consolidated financial statements adjusted to reflect as if the Merger had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to conform the classification of expenses in Midstates statements of operations to our classification for similar expenses and the estimated tax impact of pro forma adjustments. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the periods presented, nor is it necessarily indicative of future results.

For the Three Months Ended June 30, 2019

For the Six Months Ended June 30, 2019

(Unaudited) (In thousands, except per unit amounts)

Revenues
$
82,772

$
177,768

Net income (loss)

23,385

(7,742
)
Earnings per share:

Basic
$
0.57

$
(0.18
)
Diluted
$
0.57

$
(0.18
)

Note 5. Fair Value Measurements of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All 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 June 30, 2020 and December 31, 2019. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

~~Derivative Instruments~~

~~Commodity derivative contracts reflected in the unaudited condensed consolidated balance sheets are recorded at estimated~~The fair ~~value. At September 30, 2017, all~~market values of the ~~Company’s~~derivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019 were based on estimated forward commodity ~~derivative contracts were with four bank counterparties~~prices. Financial assets and ~~were~~liabilities are classified ~~as Level 2 in~~based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input ~~hierarchy. The~~to the fair value ofmeasurement requires judgment, and may affect the Company’s commodity derivatives are determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially allvaluation of ~~these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.~~

~~Derivative instruments listed below are presented gross and include swaps and collars that are carried at fair value. The Company records the net change in~~ the fair value of ~~these positions in “Gains (losses) on commodity derivative contracts — net” in~~assets and liabilities and their placement within the ~~Company’s unaudited condensed consolidated statements of operations.~~

Fair Value Measurements at September 30, 2017

Significant Other

Significant

Quoted Prices in Active
Markets (Level 1)

Observable Inputs
(Level 2)

Unobservable Inputs
(Level 3)

Total

(in thousands)

Derivative Assets:

Commodity derivative oil swaps

$
—

$
722

$
—

$
722

Commodity derivative gas swaps

$
—

$
1,006

$
—

$
1,006

Commodity derivative oil collars

$
—

$
2,356

$
—

$
2,356

Commodity derivative gas collars

$
—

$
2,806

$
—

$
2,806

Total assets

$
—

$
6,890

$
—

$
6,890

Derivative Liabilities:

Commodity derivative oil swaps

$
—

$
(772
)
$
—

$
(772
)
Commodity derivative gas swaps

$
—

$
—

$
—

$
—

Commodity derivative oil collars

$
—

$
(1,380
)
$
—

$
(1,380
)
Commodity derivative gas collars

$
—

$
(2,120
)
$
—

$
(2,120
)
Total liabilities

$
—

$
(4,272
)
$
—

$
(4,272
)

fair value hierarchy levels.

~~At December 31, 2016, the Company did not have any open commodity derivative contract positions.~~16

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4.The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2020 and December 31, 2019 for each of the fair value hierarchy levels:

Fair Value Measurements at June 30, 2020 Using

Quoted Prices in

Significant Other

Significant

Active Market

Observable Inputs

Unobservable Inputs

(Level 1)

(Level 2)

(Level 3)

Fair Value

(In thousands)

Assets:

Commodity derivatives
$
—

$
49,302

$
—

$
49,302

Interest rate derivatives

—

—

—

—

Total assets
$
—

$
49,302

$
—

$
49,302

Liabilities:

Commodity derivatives
$
—

$
6,877

$
—

$
6,877

Interest rate derivatives

—

3,693

—

3,693

Total liabilities
$
—

$
10,570

$
—

$
10,570

Fair Value Measurements at December 31, 2019 Using

Quoted Prices in

Significant Other

Significant

Active Market

Observable Inputs

Unobservable Inputs

(Level 1)

(Level 2)

(Level 3)

Fair Value

(In thousands)

Assets:

Commodity derivatives
$
—

$
18,509

$
—

$
18,509

Interest rate derivatives

—

595

—

595

Total assets
$
—

$
19,104

$
—

$
19,104

Liabilities:

Commodity derivatives
$
—

$
6,861

$
—

$
6,861

Interest rate derivatives

—

558

—

558

Total liabilities
$
—

$
7,419

$
—

$
7,419

See Note 6 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets. The following methods and assumptions are used to estimate the fair values:

•

The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. The initial fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See Note 7 for a summary of changes in AROs.

•

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The Company uses an income approach based on the discounted cash flow method, whereby the present value of expected future net cash flows are discounted by applying an appropriate discount rate, for purposes of placing a fair value on the assets. The future cash flows are based on management’s estimates for the future. The unobservable inputs used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties (some of which are Level 3 inputs within the fair value hierarchy).

•

NaN impairment expense for the three months ended June 30, 2020 was recognized.

AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
•
For the six months ended June 30, 2020, we recognized $405.7 million of impairment expense on our proved oil and natural gas properties. These impairments related to certain properties located in East Texas, the Rockies and offshore Southern California. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. The impairments were due to a decline in the value of estimated proved reserves based on declining commodity prices.
•
NaN impairment expense was recognized during the three and six months ended June 30, 2019.

Note 6. Risk Management and Derivative Instruments

~~The Company’s production is exposed~~Derivative instruments are utilized to manage exposure to commodity price fluctuations and achieve a more predictable cash flow in ~~crude oil, NGLs and~~connection with natural gas ~~prices. The Company believes it is prudent~~and oil sales from production and borrowing related activities. These instruments limit exposure to ~~manage~~declines in prices, but also limit the variability in cash flows by, at times, entering into derivative financial instruments to economically hedge a portion of its crude oil, NGLs and natural gas production. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices.benefits that would be realized if prices increase.

· ~~Swaps: The Company receives or pays a fixed price for the commodity and pays or receives a floating market price to the counterparty. The fixed-price payment and the floating-price payment~~Certain inherent business risks are ~~netted, resulting in a net amount due to or from the counterparty.~~

· Collars: A collar contains a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

· Three-way collars: A three-way collar contains a fixed floor price (long put), fixed sub-floor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, the Company receives the ceiling strike price and pays the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the sub-floor price, the Company receives the floor strike price and pays the market price. If the market price is below the sub-floor price, the Company receives the market price plus the difference between the floor and the sub-floor strike prices and pays the market price.

~~These derivative contracts are placed~~associated with ~~major financial institutions that the Company believes are minimal credit risks. The crude oil, NGLs and natural gas reference prices upon which the~~ commodity derivative contracts, ~~are based reflect various market indices that management believes correlates with actual prices received by the Company for its crude oil, NGLs and natural gas production.~~

~~Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks,~~ including market risk and credit risk. Market risk is the risk that the price of ~~the commodity~~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 ~~Company’s~~ counterparty to a contract. ~~The Company does~~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 ~~require collateral from its~~required to be posted by counterparties, ~~but does attempt to minimize its~~ 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, which management believes present minimal credit risk. In addition,~~institutions. Additionally, master netting agreements are used to mitigate ~~its~~ risk of loss due to default ~~the Company has~~with counterparties on derivative instruments. We have also entered into ~~agreements~~International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with ~~its~~each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of ~~its derivative instruments that allow~~set-off upon the ~~Company to offset its asset position with its liability position in the event~~occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the ~~counterparty. Due~~party not in default may set-off all liabilities owed to the ~~netting arrangements,~~defaulting party against all net derivative asset receivables from the defaulting party. Had all counterparties failed completely to perform according to the terms of the existing contracts, we would have had the ~~Company’s counterparties failed~~right to ~~perform~~offset $39.9 million against amounts outstanding under ~~existing~~our Revolving Credit Facility at June 30, 2020, reducing our maximum credit exposure to approximately $0.3 million, all of which was with one counterparty. See Note 8 for additional information regarding our Revolving Credit Facility.

Commodity Derivatives

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

In April 2020, the ~~maximum loss at September 30, 2017 would have been $2.6~~Company monetized a portion of its 2021 crude oil hedges for total cash proceeds of approximately $18.0 million.

~~Commodity Derivative Contracts~~

~~The Company has entered~~We enter into ~~various oil and~~ natural gas derivative contracts that ~~extend through March 2019, summarized as follows:~~

NYMEX WTI

Fixed Swaps

Collars

Three Way Collars

Hedge
Position
(Bbls)

Weighted
Avg
Strike
Price

Hedge
Position
(Bbls)

Weighted
Avg Ceiling
Price

Weighted
Avg Floor
Price

Hedge
Position
(Bbls)

Weighted
Avg
Ceiling
Price

Weighted
Avg Floor
Price

Weighted
Avg
Sub-Floor
Price

Quarter Ended:

September 30, 2017(2)

207,000

$
55.29

46,000

$
60.00

$
50.00

115,000

$
62.80

$
50.00

$
40.00

December 31, 2017(1)(2)

276,000

$
53.58

46,000

$
60.00

$
50.00

115,000

$
62.80

$
50.00

$
40.00

March 31, 2018(1)

99,000

$
50.61

—

$
—

$
—

225,000

$
62.14

$
50.00

$
40.00

June 30, 2018(1)

145,600

$
51.22

—

$
—

$
—

182,000

$
60.65

$
50.00

$
40.00

September 30, 2018(1)

92,000

$
50.38

—

$
—

$
—

184,000

$
59.93

$
50.00

$
40.00

December 31, 2018(1)

92,000

$
50.38

—

$
—

$
—

46,000

$
56.70

$
50.00

$
40.00

NYMEX HENRY HUB

Fixed Swaps

Collars

Three Way Collars

Hedge
Position
(MMBtu)

Weighted
Avg Strike
Price

Hedge
Position
(MMBtu)

Weighted
Avg Ceiling
Price

Weighted
Avg Floor
Price

Hedge
Position
(MMBtu)

Weighted
Avg
Ceiling
Price

Weighted
Avg
Floor
Price

Weighted
Avg
Sub-Floor
Price

Quarter Ended:

September 30, 2017

2,944,000

$
3.38

368,000

$
3.63

$
3.15

—

$
—

$
—

$
—

December 31, 2017(1)

1,907,000

$
3.43

551,000

$
3.84

$
3.23

610,000

$
4.30

$
3.25

$
2.50

March 31, 2018(1)(3)

1,350,000

$
3.47

—

$
—

$
—

1,530,000

$
4.38

$
3.25

$
2.50

June 30, 2018(1)

—

$
—

—

$
—

$
—

1,365,000

$
3.40

$
3.00

$
2.50

September 30, 2018(1)

—

$
—

—

$
—

$
—

1,380,000

$
3.40

$
3.00

$
2.50

December 31, 2018(1)

—

$
—

—

$
—

$
—

1,380,000

$
3.40

$
3.00

$
2.50

March 31, 2019(1)

—

$
—

—

$
—

$
—

1,350,000

$
3.40

$
3.00

$
2.50

~~(1)~~ ~~Positions shown represent open commodity derivative contract positions as of September 30, 2017. The Company did not have any open commodity derivative contract positions as of December 31, 2016.~~

~~(2)~~ ~~During the second quarter, the Company entered~~are indexed to NYMEX-Henry Hub. We also enter into ~~long call oil trades to offset its three way collar short calls for the second half of 2017.~~

~~(3)~~ ~~During the second quarter, the Company entered into natural gas three way collars with long call ceilings in order to offset its Q1 2018 natural gas fixed swaps.~~

~~Subsequent to September 30, 2017, the Company entered into various~~ oil derivative contracts ~~that extend through December 2019, summarized as follows:~~indexed to NYMEX-WTI. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At June 30, 2020, we had the following open commodity positions:

Remaining

2020

2021

2022

Natural Gas Derivative Contracts:

Fixed price swap contracts:

Average monthly volume (MMBtu)

1,450,000

925,000

500,000

Weighted-average fixed price
$
2.26

$
2.49

$
2.45

Collar contracts:

Two-way collars

Average monthly volume (MMBtu)

420,000

925,000

200,000

Weighted-average floor price
$
2.60

$
2.10

$
2.10

Weighted-average ceiling price
$
2.88

$
3.28

$
2.99

Natural Gas Basis Swaps:

PEPL basis swaps:

Average monthly volume (MMBtu)

600,000

500,000

—

Weighted-average spread
$
(0.46
)

$
(0.40
)

$
—

Crude Oil Derivative Contracts:

Fixed price swap contracts:

Average monthly volume (Bbls)

199,300

33,750

30,000

Weighted-average fixed price
$
57.41

$
56.57

$
55.32

Collar contracts:

Two-way collars

Average monthly volume (Bbls)

14,300

—

—

Weighted-average floor price
$
55.00

$
—

$
—

Weighted-average ceiling price
$
62.10

$
—

$
—

Three-way collars

Average monthly volume (Bbls)

30,500

—

—

Weighted-average ceiling price
$
65.75

$
—

$
—

Weighted-average floor price
$
50.00

$
—

$
—

Weighted-average sub-floor price
$
40.00

$
—

$
—

NGL Derivative Contracts:

Fixed price swap contracts:

Average monthly volume (Bbls)

111,450

22,800

—

Weighted-average fixed price
$
21.99

$
24.25

$
—

Interest Rate Swaps

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 June 30, 2020, we had the following interest rate swap open positions:

Remaining

2020

2021

2022

Average Monthly Notional (in thousands)
$
125,000

$
125,000

$
75,000

Weighted-average fixed rate

1.612
%

1.612
%

1.281
%
Floating rate
1 Month LIBOR

1 Month LIBOR

1 Month LIBOR

AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheet Presentation

The following table summarizes both: (i) the ~~net~~gross fair ~~values~~value of ~~commodity~~ derivative instruments by the appropriate balance sheet classification ineven when the ~~Company’s unaudited condensed consolidated balance sheets at September 30, 2017 (in thousands):~~

Type

Balance Sheet Location (1)

September 30, 2017

Oil swaps

Derivative financial instruments — current assets

$
49

Gas swaps

Derivative financial instruments — current assets

1,006

Oil collars

Derivative financial instruments — current assets

969

Gas collars

Derivative financial instruments — current assets

872

Oil swaps

Derivative financial instruments — noncurrent liabilities

(98
)
Oil collars

Derivative financial instruments — noncurrent liabilities

6

Gas collars

Derivative financial instruments — noncurrent liabilities

(186
)
Total derivative fair value at period end

$
2,618

~~(1)~~ ~~The fair values of commodity~~ derivative instruments ~~reported in the Company’s unaudited condensed consolidated balance sheets~~ are subject to netting arrangements and qualify for net ~~presentation.~~presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at June 30, 2020 and December 31, 2019. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our Revolving Credit Facility.

		Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives
		June 30,			June 30,			December 31,			December 31,
Type	Balance Sheet Location	2020			2020			2019			2019
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	38,035		$	4,744		$	11,518		$	5,887
Interest rate swaps	Short-term derivative instruments		—			1,860			248			253
Gross fair value			38,035			6,604			11,766			6,140
Netting arrangements			(5,819	)		(5,819	)		(5,887	)		(5,887	)
Net recorded fair value	Short-term derivative instruments	$	32,216		$	785		$	5,879		$	253

Commodity contracts	Long-term derivative instruments	$	11,267		$	2,133		$	6,990		$	973
Interest rate swaps	Long-term derivative instruments		—			1,833			347			305
Gross fair value			11,267			3,966			7,337			1,278
Netting arrangements			(2,133	)		(2,133	)		(973	)		(973	)
Net recorded fair value	Long-term derivative instruments	$	9,134		$	1,833		$	6,364		$	305

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying Unaudited Condensed Statements of Consolidated Operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):

		For the Three Months Ended					For the Six Months Ended
	Statements of	June 30,					June 30,
	Operations Location	2020		2019			2020			2019
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	19,165	$	(22,993	)	$	(88,548	)	$	9,494
(Gain) loss on interest rate derivatives	Interest expense, net		438		627			4,054			534

Note 7. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the Company’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2020 (in thousands):

Asset retirement obligations at beginning of period	$	91,089
Liabilities added from acquisition or drilling		50
Liabilities settled		—
Accretion expense		3,052
Revision of estimates		—
Asset retirement obligation at end of period		94,191
Less: Current portion		(623	)
Asset retirement obligations - long-term portion	$	93,568

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Long-Term Debt

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

	June 30,		December 31,
	2020		2019
	(In thousands)
Revolving Credit Facility (1)	$	280,000	$	285,000
Paycheck Protection Program loan (2)		5,516		—
Total debt		285,516		285,000
Current portion of long-term debt (3)		20,000		—
Long-term debt	$	265,516	$	285,000

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

(2)	See below for additional information regarding the receipt of the paycheck protection program loan.

(3)	Reflects the current portion of the monthly reductions for the Revolving Credit Facility as described below regarding the Third Amendment (as defined below).

Revolving Credit Facility

Amplify Energy Operating LLC, our wholly owned subsidiary (“OLLC”), is a party to a reserve-based revolving credit facility (the “Revolving Credit Facility”), subject to a borrowing base of $285.0 million as of June 30, 2020, which is guaranteed by us and all of our current subsidiaries. The Revolving Credit Facility matures on November 2, 2023.

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

As of June 30, 2020, we were in compliance with all the financial (current ratio and total leverage ratio) and other covenants associated with our Revolving Credit Facility.

Borrowing Base Redetermination

On June 12, 2020, the Company entered into the Borrowing Base Redetermination Agreement and Third Amendment to Credit Agreement, among the Borrower, Amplify Acquisitionco LLC, a Delaware limited liability company, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “Third Amendment”). The Third Amendment amends the parties’ existing Credit Agreement, dated November 2, 2018, to among other things:

•

reduce the borrowing base under the Credit Agreement from $450.0 million to $285.0 million, with monthly reductions of $5.0 million thereafter until the borrowing base is reduced to $260.0 million, effective November 1, 2020;

•

increase the amount of first priority liens on all assets from at least 85% to 90%;

•

suspend certain financial covenants for the quarter ended June 30, 2020;

•

amend the definition of “Consolidated EBITDAX” in the Credit Agreement to decrease the limit of cash and cash equivalents permitted from $30.0 million to $25.0 million and increase the limit of transaction-related expense add-backs from $5.0 million to $20.0 million;

•

increase the minimum hedging requirements to at least 30% -60% of our estimated production from total proved developed producing reserves;

•

incorporate a mandatory prepayment at times when cash and cash equivalents (as defined in the Credit Agreement) on hand exceed $25.0 million for five consecutive business days; and

•

amend certain other covenants and provisions.

Weighted-Average Interest Rates

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

	For the Three Months Ended		For the Six Months Ended
	June 30,		June 30,
	2020	2019	2020	2019
Revolving Credit Facility	3.12%	5.00%	3.55%	5.04%

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Letters of Credit

At June 30, 2020, we had 0 letters of credit outstanding.

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with our Revolving Credit Facility was $1.7 million at June 30, 2020. At June 30, 2020, the unamortized deferred financing costs are amortized over the remaining life of our Revolving Credit Facility. At June 30, 2020, we wrote-off $2.4 million of deferred financing costs in connection with the decrease in our borrowing base.

Paycheck Protection Program

On April 24, 2020, the Company received a $5.5 million loan under the Paycheck Protection Program (the “PPP Loan”). The Paycheck Protection Program was established as part of the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) to provide loans to qualifying businesses. The loans and accrued interest are potentially forgivable provided that the borrower uses the loan proceeds for eligible purposes. At this time, the Company anticipates that a substantial majority of the loan proceeds will be forgiven under the program. The term of the Company’s PPP Loan is two years with an annual interest rate of 1% and 0 payments of principal or interest due during the six-month period beginning on the date of the PPP Loan.

Note 9. Equity (Deficit)

Common Stock

The Company’s authorized capital stock includes 250,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common stock issued for the six months ended June 30, 2020:

	Common
	Shares
Balance, December 31, 2019		37,566,540
Issuance of common stock		—
Restricted stock units vested		64,751
Repurchase of common shares (1)		(18,377	)
Balance, June 30, 2020		37,612,914

(1)

Represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.

Warrants

On the May 4, 2017, Legacy Amplify entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent (“AST”), pursuant to which Legacy Amplify issued warrants to purchase up to 2,173,913 shares of Legacy Amplify’s common stock (representing 8% of Legacy Amplify’s outstanding common stock as of May 4, 2017), including shares of Legacy Amplify’s common stock issuable upon full exercise of the warrants, but excluding any common stock issuable under Legacy Amplify’s Management Incentive Plan, exercisable for a five-year period commencing on May 4, 2017 at an exercise price of $42.60 per share.

On the effective date of the Merger, Legacy Amplify, Midstates and AST entered into an Assignment and Assumption Agreement, pursuant to which the Company agreed to assume Legacy Amplify’s Warrant Agreement.

In connection with the Merger in August 2019, the Company assumed outstanding warrants of 4,647,520 Third Lien Notes Warrants at an exercise price of $22.78 per share (the “Third Lien Warrants”) and 2,332,089 Unsecured Creditor Warrants at an exercise price of $43.67 per share (the “Unsecured Creditor Warrants” and collectively with the Third Lien Warrants, the “Warrants”). As a result of the Merger, the value of the outstanding Warrants was adjusted downward based on the low stock price and estimated fair value as of the Merger date. The Warrants expired on April 21, 2020.

Share Repurchase Program

On December 21, 2018, Legacy Amplify’s board of directors authorized the repurchase of up to $25.0 million of Legacy Amplify outstanding shares of common stock, with repurchases beginning on January 9, 2019. During the six months ended June 30, 2019, Legacy Amplify repurchased 169,400 shares of common stock at an average price of $7.35 for a total cost of approximately $1.3 million. On April 18, 2019, in anticipation of the Merger, Legacy Amplify terminated the repurchase program.

In connection, with the closing of the Merger, the board of directors approved the commencement of an open market share repurchase program of up to $25.0 million of the Company’s outstanding shares of common stock. As of February 28, 2020, the Company had repurchased approximately 4.2 million shares of common stock at an average price of $5.94 per share for a total cost of approximately $24.9 million (inclusive of fees).

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cash Dividend Payment

On March 3, 2020, our board of directors approved a dividend of $0.10 per share of outstanding common stock or $3.8 million in aggregate, which was paid on March 30, 2020, to stockholders of record at the close of business on March 16, 2020. The board of directors of the Company previously decided to suspend the quarterly dividend program until further notice. Under the terms of our Credit Agreement, dividends are restricted based upon certain leverage and liquidity covenants. Future dividends, if any, are subject to these debt covenants and discretionary approval by the board of directors.

Note 10. Earnings per Share

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

	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2020			2019		2020			2019
Net loss	$	(41,336	)	$	18,641	$	(408,535	)	$	(12,836	)
Less: Net income allocated to participating restricted stockholders		—			728		—			—
Basic and diluted earnings available to common stockholders	$	(41,336	)	$	17,913	$	(408,535	)	$	(12,836	)

Common shares/units:
Common shares outstanding — basic		37,595			22,267		37,582			22,233
Dilutive effect of potential common shares		—			—		—			—
Common shares outstanding — diluted		37,595			22,267		37,582			22,233

Net earnings per share:
Basic	$	(1.10	)	$	0.80	$	(10.87	)	$	(0.58	)
Diluted	$	(1.10	)	$	0.80	$	(10.87	)	$	(0.58	)
Antidilutive warrants (1)		2,174			2,174		2,174			2,174

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

Note 11. Long-Term Incentive Plans

In May 2017, Legacy Amplify implemented the Management Incentive Plan (the “Legacy Amplify MIP”). In connection with the closing of the Merger, on August 6, 2019, the Company assumed the Legacy Amplify MIP.

Restricted Stock Units

Restricted Stock Units with Service Vesting Condition

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 $0.5 million at June 30, 2020. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.7 years.

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

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
TSUs outstanding at December 31, 2019		291,370		$	5.18
Granted (2)		43,250		$	3.10
Forfeited		(87,314	)	$	5.12
Vested		(57,492	)	$	5.12
TSUs outstanding at June 30, 2020		189,814		$	4.75

(1)

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

(2)

The aggregate grant date fair value of TSUs issued for the six months ended June 30, 2020 was $0.1 million based on a grant date market price of ranging from $0.54 to $6.61 per share.

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Restricted Stock Units with Market and Service Vesting Conditions

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 approximately $0.2 million at June 30, 2020. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.6 years.

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.

The assumptions used to estimate the fair value of the PSUs are as follows:

Share price targets	$	12.50		$	15.00		$	17.50

Risk-free interest rate:
Awards Issued on January 1, 2020		1.61	%		1.61	%		1.61	%

Dividend yield		12.1	%		12.1	%		12.1	%

Expected volatility:
Awards Issued on January 1, 2020		60.0	%		60.0	%		60.0	%

Calculated fair value per PSU:
Awards Issued on January 1, 2020	$	3.66		$	2.98		$	2.46

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

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
PSUs outstanding at December 31, 2019		305,893		$	2.15
Granted (2)		43,250		$	3.03
Forfeited		(128,058	)	$	2.11
Vested		—		$	—
PSUs outstanding at June 30, 2020		221,085		$	2.35

(1)

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

(2)

The aggregate grant date fair value of PSUs issued for the six months ended June 30, 2020 was $0.1 million based on a calculated fair value price ranging from $2.46 to $3.66 per share.

2017 Non-Employee Directors Compensation Plan

In June 2017, Legacy Amplify implemented the 2017 Non-Employee Directors Compensation Plan (“Legacy Amplify Non-Employee Directors Compensation Plan”) to attract and retain the services of experienced non-employee directors of Legacy Amplify or its subsidiaries. In connection with the closing of the Merger, on August 6, 2019, the Company assumed the Legacy Amplify Non-Employee 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 less than $0.1 million at June 30, 2020. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.8 years.

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information regarding the ~~location~~Board RSUs granted under the Legacy Amplify Non-Employee Directors Compensation Plan for the period presented:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Board RSUs outstanding at December 31, 2019		16,157		$	5.12
Granted		—		$	—
Forfeited		—		$	—
Vested		(7,259	)	$	5.12
Board RSUs outstanding at June 30, 2020		8,898		$	5.12

(1)

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

Compensation Expense

The following table summarizes the amount of recognized compensation expense associated with the Legacy Amplify MIP and ~~fair value amounts of all commodity derivative instruments~~Legacy Amplify Non-Employee Directors Compensation Plan, which are reflected in the ~~unaudited condensed consolidated balance sheets, as well as~~accompanying Unaudited Condensed Statements of Consolidated Operations for the ~~gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets at September 30, 2017~~periods presented (in thousands):

September 30, 2017

Not Designated as

Gross Recognized

Gross Amounts

Net Recognized
Fair Value

ASC 815 Hedges

Balance Sheet Location Classification

Assets/Liabilities

Offset

Assets/Liabilities

Derivative Assets:

Commodity contracts

Derivative financial instruments — current

$
5,858

$
(2,962
)
$
2,896

Commodity contracts

Derivative financial instruments — noncurrent

1,032

(1,032
)
—

$
6,890

$
(3,994
)
$
2,896

Derivative Liabilities:

Commodity contracts

Derivative financial instruments — current

$
(2,962
)
$
2,962

$
—

Commodity contracts

Derivative financial instruments — noncurrent

(1,310
)
1,032

(278
)

$
(4,272
)
$
3,994

$
(278
)

	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2020			2019		2020		2019
Equity classified awards
TSUs	$	(6	)	$	532	$	125	$	1,202
PSUs		5			309		10		705
Board RSUs		2			50		40		162
	$	1		$	891	$	175	$	2,069

~~As of December 31, 2016,~~Note 12. Leases

For the ~~Company~~quarter ended June 30, 2020, our leases qualify as operating leases and we did not have any ~~open commodity derivative contract positions.~~existing or new leases qualifying as financing leases or variable 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.

~~Gains/Losses on Commodity Derivative Contracts~~

~~The Company~~Our corporate office lease does not ~~designate its commodity derivative contracts as hedging instruments~~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 ~~financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with~~our office equipment and vehicle leases.

For the ~~change in fair value during~~six months ended June 30, 2020 and 2019, we recognized approximately $1.2 million and $1.0 million, respectively, of costs relating to the ~~periodic reporting period recognized currently as a gain or loss in “Gains (losses) on commodity derivative contracts—net” within revenues~~operating leases in the ~~unaudited condensed consolidated statements~~Unaudited Condensed Statement of ~~operations.~~Operations.

Supplemental cash flow information related to the Company’s lease liabilities are included in the table below:

	For the Six Months Ended
	June 30,
	2020		2019
	(In thousands)
Non-cash amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	877	$	5,096

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents ~~net~~the Company’s right-of-use assets and lease liabilities for the period presented:

	June 30,		December 31,
	2020		2019
	(In thousands)
Right-of-use asset	$	3,528	$	4,406

Lease liabilities:
Current lease liability		2,205		1,712
Long-term lease liability		1,350		2,720
Total lease liability	$	3,555	$	4,432

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):

	Office leases		Leased vehicles and office equipment		Total
Remaining in 2020	$	808	$	353	$	1,161
2021		1,287		536		1,823
2022		478		208		686
2023 and thereafter		—		25		25
Total lease payments		2,573		1,122		3,695
Less: interest		105		35		140
Present value of lease liabilities	$	2,468	$	1,087	$	3,555

The weighted average remaining lease terms and discount rate for all of our operating leases for the period presented:

	June 30,
	2020			2019
Weighted average remaining lease term (years):
Office leases		1.10			1.91
Vehicles		0.53			0.49
Office equipment		0.06			0.10
Weighted average discount rate:
Office leases		3.49	%		3.72	%
Vehicles		0.94	%		0.77	%
Office equipment		0.17	%		0.19	%

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

Accrued Liabilities

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

	June 30,		December 31,
	2020		2019
Accrued lease operating expense	$	8,680	$	11,794
Accrued capital expenditures		1,541		5,515
Accrued general and administrative expense		3,111		3,126
Operating lease liability		2,205		1,712
Accrued ad valorem tax		1,566		520
Asset retirement obligations		623		623
Accrued interest payable		30		36
Other		81		32
Accrued liabilities	$	17,837	$	23,358

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cash and Cash Equivalents Reconciliation

The following table provides a reconciliation of cash ~~received~~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):

	June 30,		December 31,
	2020		2019
Cash and cash equivalents	$	13,202	$	—
Restricted cash		—		325
Total cash, cash equivalents and restricted cash	$	13,202	$	325

Unproved Property

We recognized $49.3 million of impairment expense on unproved properties for ~~commodity derivative contracts~~the six months ended June 30, 2020, which was related to expiring leases and ~~unrealized net gains recorded by~~ the ~~Company~~evaluation of qualitative and quantitative factors related to the ~~change~~current decline in ~~fair value of~~commodity prices. NaN impairment expense was recorded for unproved properties for the ~~derivative instruments in “Gains (losses) on commodity derivative contracts—net”~~six months ended June 30, 2019.

Supplemental Cash Flows

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

For the Three Months Ended

For the Nine Months Ended

September 30, 2017

September 30, 2017

Net cash received for commodity derivative contracts

$
2,909

$
6,149

Unrealized net (losses) gains

(6,500
)
2,618

Gains (losses) on commodity derivative contracts—net

$
(3,591
)
$
8,767

	For the Six Months Ended
	June 30,
	2020			2019
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	5,380		$	5,861
Cash paid for reorganization items, net		351			650
Cash paid for taxes		85			—

Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities		(3,618	)		(5,034	)

~~Cash settlements, as presented~~Note 14. Related Party Transactions

Related Party Agreements

There have been no transactions in excess of $120,000 between us and any related person in which the related person had a direct or indirect material interest for the three and six months ended June 30, 2020 and 2019, respectively.

Note 15. Commitments and Contingencies

Litigation and Environmental

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 ~~table above, represent realized gains related~~reporting periods in which such matters are resolved.

Although we are insured against various risks to the ~~Company’s derivative instruments. In addition~~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 ~~cash settlements, the Company also recognizes fair value changes~~indemnify us against liabilities arising from future legal proceedings.

At June 30, 2020 and December 31, 2019, we had 0 environmental reserves recorded on its derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

our Unaudited Condensed Consolidated Balance Sheet.

~~5. Property and Equipment~~27

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Property and equipment consisted of the following as of the dates presented:~~

September 30, 2017

December 31, 2016

(in thousands)

Oil and gas properties, on the basis of full-cost accounting:

Proved properties

$
709,647

$
573,150

Unproved properties

26,178

65,080

Other property and equipment

6,543

6,339

Less accumulated depreciation, depletion and amortization

(59,349
)
(12,974
)
Net property and equipment

$
683,019

$
631,595

~~Oil and Gas Properties~~

Minimum Volume Commitment

The Company ~~capitalizes internal costs directly related~~is party to ~~exploration~~a gas purchase, gathering and ~~development activities~~processing contract in Oklahoma, which includes certain minimum NGL commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to ~~oil~~generate, when processed, the minimum levels of recovered NGLs, it would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The Company is not meeting the minimum volume required under these contractual provisions. The commitment fee expense for the six months ended June 30, 2020, was approximately $0.6 million.

The Company is party to a gas purchase, gathering and ~~gas properties. During~~processing contract in East Texas, which includes certain minimum NGL commitments. The Company anticipates that a shortfall will occur for the year-end 2020 and has established an accrual for the commitment fee expense of $0.8 million for the six months ended June 30, 2020.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

Beta Operating Company, LLC, has an obligation with the BOEM in connection with its 2009 acquisition of our properties in federal waters offshore Southern California. The Company supports this obligation with $161.3 million of A-rated surety bonds and $0.3 million of cash.

Note 16. Income Taxes

The Company had less than ($0.1) million in income tax benefit/(expense) for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016, the Company capitalized the following (in thousands):~~

Successor

Predecessor

Successor

Predecessor

Three Months
Ended

Three Months
Ended

Nine Months
Ended

Nine Months
Ended

September 30, 2017

September 30, 2016

September 30, 2017

September 30, 2016

Internal costs capitalized to oil and gas properties (1)

$
1,651

$
1,049

$
4,656

$
3,311

~~(1)~~ ~~Inclusive of $0.8 million and $0.1 million of qualifying share-based compensation expense~~2020, respectively, 0 income tax for the three months ended ~~September~~June 30, ~~2017~~2019 and ~~2016, respectively. For~~less than $0.1 million income tax benefit/(expense) for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019. The Company’s effective tax rate was 0.2% and ~~2016, inclusive of $2.0 million and $0.5 million, respectively, of qualifying share-based compensation expense.~~

The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds realized from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income. During the nine months ended September 30, 2017, the Company disposed of certain oil and gas equipment for cash proceeds of $1.4 million, which were reflected as a reduction of oil and gas properties with no gain or loss recognized. During the three months ended September 30, 2017, the Company closed on the sale of certain oil and gas properties in Lincoln County, Oklahoma, for $7.0 million in cash ($2.9 million, net after assumption of liabilities), subject to standard post-closing adjustments. The net proceeds from the sale were retained for general corporate purposes.

The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of the Company’s oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying unaudited condensed consolidated statements of operations.

~~The Company did not record an impairment of oil and gas properties during the three or nine months ended September 30, 2017.~~ The three and nine month periods ended September 30, 2016 included impairments of oil and gas properties of $33.9 million and $224.6 million, respectively. These impairments were primarily the result of continued low commodity prices, which resulted in a decrease in the discounted present value of the Company’s proved oil and natural gas reserves.

DD&A is calculated using the Units of Production Method (“UOP��). The UOP calculation multiplies the percentage of total estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A and impairment, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. The following table presents depletion expense related to oil and gas properties0.0% for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020, respectively, and ~~2016, respectively:~~

~~Oil~~0.0% and gas unproved properties include costs that are not being depleted or amortized. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made0.4% for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties and become part of our depletion base and subject to the full cost ceiling limitation. No impairment of unproved properties was recorded during the three or nine months ended September 30, 2017. Unproved property was $26.2 million and $65.1 million at September 30, 2017 and December 31, 2016, respectively.

~~Other Property and Equipment~~

Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is calculated principally using the straight-line method over the estimated useful lives of the assets, which range from five to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.

~~6. Other Noncurrent Assets~~

~~The following table presents the components of other noncurrent assets as of the dates presented:~~

September 30, 2017

December 31, 2016

(in thousands)

Deferred financing costs associated with the Exit Facility

$
1,286

$
1,187

Field equipment inventory

4,221

2,619

Other

1,649

1,649

Other noncurrent assets

$
7,156

$
5,455

~~7. Accrued Liabilities~~

~~The following table presents the components of accrued liabilities as of the dates presented:~~

September 30, 2017

December 31, 2016

(in thousands)

Accrued oil and gas capital expenditures

$
12,281

$
6,118

Accrued revenue and royalty distributions

17,707

28,262

Accrued lease operating and workover expense

6,200

8,932

Accrued interest

123

254

Accrued taxes

2,980

2,537

Compensation and benefit related accruals

5,133

3,516

Other

2,563

4,112

Accrued liabilities

$
46,987

$
53,731

~~8. Asset Retirement Obligations~~

Asset Retirement Obligations (“AROs”) represent the estimated future abandonment costs of tangible assets, such as wells, service assets and other facilities. The estimated fair value of the AROs at inception is capitalized as part of the carrying amount of the related long-lived assets.

~~The following table reflects the changes in the Company’s AROs for the periods presented (in thousands):~~

Successor

Predecessor

Nine Months
Ended

Nine Months
Ended

September 30, 2017

September 30, 2016

Asset retirement obligations — beginning of period

$
14,200

$
18,708

Liabilities incurred

259

520

Revisions

—

—

Liabilities settled

(107
)

(278
)
Liabilities eliminated through asset sales

(1,146
)

—

Current period accretion expense

833

1,316

Asset retirement obligations — end of period

$
14,039

$
20,266

~~9. Debt~~

~~Exit Facility~~

At September 30, 2017 and December 31, 2016, the Company maintained a reserves based credit facility with a borrowing base of $170.0 million (the “Exit Facility”). At September 30, 2017, and December 31, 2016, the Company had $128.1 million drawn on the Exit Facility and had outstanding letters of credit obligations totaling $1.9 million. As of September 30, 2017, the Company had $40.0 million of availability on the Exit Facility.

The Exit Facility bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. For the three months ended September 30, 2017, the weighted average interest rate was 5.7%. Unamortized debt issuance costs of $1.3 million and $1.2 million associated with the Exit Facility are included in “Other noncurrent assets” on the unaudited condensed consolidated balance sheets at September 30, 2017, and December 31, 2016, respectively.

In addition to interest expense, the Exit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter.

On May 24, 2017, the Company entered into the First Amendment to the Exit Facility (the “First Amendment”). The First Amendment, among other items, (i) moved the first scheduled borrowing base redetermination from April 2018 to October 2017; (ii) removed the requirement to maintain a cash collateral account with the administrative agent in the amount of $40.0 million; (iii) removed the requirement to maintain at least 20% liquidity of the then effective borrowing base; (iv) amended the required mortgage threshold from 95% to 90%; (v) amended the threshold amount for which the borrower is required to provide advance notice to the administrative agent of a sale or disposition of oil and gas properties which occurs during the period between two successive redeterminations of the borrowing base; (vi) amended the required ratio of total net indebtedness to EBITDA from 2.25:1.00 to 4.00:1.00; (vii) amended the required EBITDA to interest coverage ratio from not less than 3.00:1.00 to not less than 2.50:1.00; and (viii) removed certain limitations on capital expenditures.

~~As of September 30, 2017, the Company was in compliance with its debt covenants.~~

On October 27, 2017, the Company’s borrowing base was redetermined at the existing amount of $170.0 million. The Company’s Anadarko Basin assets in Texas and Oklahoma were excluded from the redetermination of the borrowing base.

~~The Company believes the carrying amount of the Exit Facility at September 30, 2017 approximates its fair value (Level 2) due to the variable nature of the Exit Facility interest rate.~~

~~10. Equity and Share-Based Compensation~~

~~Common Shares~~

~~Share Activity~~

~~The following table summarizes changes in the number of outstanding shares during the nine months ended September 30, 2017:~~

Common
Stock

Treasury
Stock(1)

Share count as of December 31, 2016

24,994,867

—

Common stock issued

103,967

—

Acquisition of treasury stock

—

(33,409
)
Share count as of September 30, 2017

25,098,834

(33,409
)

~~(1)~~ ~~Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.~~

~~Share-Based Compensation~~

~~2016 Long Term Incentive Plan~~

On the Effective Date, the Company established the 2016 LTIP and filed a Form S-8 with the SEC, registering 3,513,950 shares for issuance under the terms of the 2016 LTIP to employees, directors and certain other persons (the “Award Shares”). The types of awards that may be granted under the 2016 LTIP include stock options, restricted stock units, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock of the reorganized Company, as well as certain cash-based awards (the “Awards”). The terms of each award are as determined by the Compensation Committee of the Board of Directors. Awards that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future issuance under the 2016 LTIP. At September 30, 2017, 2,299,088 Award Shares remain available for issuance under the terms of the 2016 LTIP.

~~Restricted Stock Units~~

At September 30, 2017, the Company had 494,794 non-vested restricted stock units outstanding to employees and non-employee directors pursuant to the 2016 LTIP, excluding restricted stock units issued to non-employee directors containing a market condition, which are discussed below. Restricted stock units granted to employees under the 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Restricted stock units granted to non-employee directors vest on the first to occur of (i) December 31, 2017, (ii) the date the non-employee director ceases to be a director of the Board (other than for cause), (iii) the director’s death, (iv) the director’s disability or (v) a change in control of the Company.

~~The fair value of restricted stock units was based on grant date fair value of the Company’s common stock. Compensation expense is recognized ratably over the requisite service period.~~

~~The following table summarizes the Company’s non-vested restricted stock unit award activity for the nine months ended September 30, 2017:~~

Restricted Stock

Weighted Average
Grant Date
Fair Value

Non-vested shares outstanding at December 31, 2016

685,662

$
19.66

Granted

17,500

$
18.62

Vested

(103,967
)
$
19.66

Forfeited

(104,401
)
$
19.66

Non-vested shares outstanding at September 30, 2017

494,794

$
19.63

Unrecognized expense as of September 30, 2017, for all outstanding restricted stock units under the 2016 LTIP was $3.9 million and will be recognized over a weighted average period of 1.2 years. Subsequent to September 30, 2017, 174,135 restricted stock units vested before consideration of minimum statutory tax withholding requirements.

On August 22, 2017, the Company amended the employment agreement of Fredric F. Brace, former President and Chief Executive Officer (the “Executive Employment Amendment”). Among other provisions, the Executive Employment Amendment accelerated the vesting of all outstanding equity awards of Mr. Brace to October 21, 2017. As a result, approximately $0.8 million of compensation expense associated with Mr. Brace’s non-vested restricted stock was accelerated into the three and ~~nine~~six months ended ~~September~~June 30, ~~2017.~~

~~Stock Options~~

~~At September 30, 2017, the Company had 423,438 non-vested stock options outstanding pursuant to the 2016 LTIP. Stock Option Awards granted~~ under the 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Stock Option Awards expire 10 years from the grant date.

2019, respectively. The Company utilizes the Black-Scholes-Merton option pricing model to determine the fair value of stock option awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility.

~~The following table summarizes the Company’s 2016 LTIP non-vested stock option activity~~effective tax rates for ~~the nine months ended September 30, 2017:~~

Options

Range of Exercise
Prices

Weighted
Average
Exercise Price

Weighted
Average
Remaining
Contractual
Term (Years)

Stock options outstanding at December 31, 2016

627,806

$
19.66

9.1

Granted

4,000

$
19.08

$
19.08

9.5

Vested

(103,967
)
$
19.08-20.97

$
19.66

—

Forfeited

(104,401
)
$
19.66

$
19.66

—

Stock options outstanding at September 30, 2017

423,438

$
19.66

9.1

Vested and exercisable at end of period(1)

103,967

$
19.08-20.97

$
19.66

9.1

~~(1) Vested and exercisable options at September 30, 2017, had no aggregate intrinsic value.~~

Unrecognized expense as of September 30, 2017, for all outstanding stock options under the 2016 LTIP was $1.9 million and will be recognized over a weighted average period of 1.3 years. Subsequent to September 30, 2017, 171,885 stock options vested before consideration of minimum statutory tax withholding requirements.

On August 22, 2017, the Company amended the Executive Employment Amendment. Among other provisions, the Executive Employment Amendment accelerated the vesting of all outstanding equity awards of Mr. Brace to October 21, 2017. As a result, approximately $0.4 million of compensation expense associated with Mr. Brace’s non-vested stock options was accelerated into the three and ~~nine~~six months ended ~~September~~June 30, ~~2017.~~

~~Non-Employee Director Restricted Stock Units Containing a Market Condition~~

~~On November 23, 2016,~~2020 and 2019 are different from the Company issued certain restricted stock units to non-employee directors that contain a market vesting condition. These restricted stock units will vest (i) on the first business day following the date on which the trailing 60-day average share price (including any dividends paid) of the Company’s common stock is equal to or greater than $30.00 or (ii) upon a change in control of the Company. Additionally, all unvested restricted stock units containing a market vesting condition will be immediately forfeited upon the first to occur of (i) the fifth (5th) anniversary of the grant date or (ii) any participant’s termination as a director for any reason (except for a termination as part of a change in control of the Company).

These restricted stock awards are accounted for as liability awards under FASB ASC 718 as the awards allow for the withholding of taxes at the discretion of the non-employee director. The liability is re-measured, with a corresponding adjustment to earnings, at each fiscal quarter-end during the performance cycle. The liability and related compensation expense of these awards for each period is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the non-employee directors.

The restricted stock unit awards issued to non-employee directors containing a market condition has a derived service period of one year. At September 30, 2017, the Company recorded a $0.7 million liability included within “Accrued liabilities” in the unaudited condensed consolidated balance sheets related to the market condition awards. The fair value of the restricted stock containing a market condition was $11.05 per unit at September 30, 2017.

~~As of September 30, 2017, unrecognized stock-based compensation related to market condition awards was $0.1 million and will be recognized over a weighted-average period of 0.1 years.~~

~~11. Income Taxes~~

~~For the nine months ended September 30, 2017, the Company recorded no income tax expense or benefit. The significant difference between our effective tax rate and the~~statutory U.S. federal ~~statutory~~ income tax rate ~~of 35% is~~ primarily due to our recorded valuation allowances.

In March 2020, the ~~effect~~President of ~~changes in~~ the ~~Company’s valuation allowance.~~ ~~During~~United States signed the ~~nine months ended September 30, 2017,~~CARES Act, to stabilize the ~~Company’s valuation allowance decreased by $13.0 million from December 31, 2016, bringing~~economy during the ~~total valuation allowance to $147.8 million at September 30, 2017. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred~~coronavirus pandemic. The CARES Act temporarily suspends and modifies certain tax ~~assets are realizable.~~

The Company expects to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.

~~12. Earnings (Loss) Per Share~~

~~Successor~~

The following table provides a reconciliation of net income attributable to common shareholders and weighted average common shares outstanding for basic and diluted earnings per share for the Successor Periods presented:

Three Months Ended

Nine Months Ended

September 30, 2017

September 30, 2017

(in thousands, except per
share amounts)

(in thousands, except per
share amounts)

Net Earnings:

Net income

$
3,663

$
35,890

Participating securities—non-vested restricted stock

(82
)
(932
)
Basic and diluted earnings

$
3,581

$
34,958

Common Shares:

Common shares outstanding — basic (1)

25,116

25,074

Dilutive effect of potential common shares

—

—

Common shares outstanding — diluted

25,116

25,074

Net Earnings Per Share:

Basic

$
0.14

$
1.39

Diluted

$
0.14

$
1.39

Antidilutive stock options (2)

424

526

Antidilutive warrants (3)

6,626

6,626

~~(1)~~ Weighted-average common shares outstanding for basic and diluted earnings per share purposes includes 17,533 shares of common stock that, while not issued and outstanding at September 30, 2017, are requiredlaws established by the ~~Plan~~2017 tax reform law known as the Tax Cuts and Jobs Act, including, but not limited to, ~~be issued.~~

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

~~(3)~~ ~~Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.~~

~~Predecessor~~

The Company’s nonvested stock awards, which were granted as part of the 2012 LTIP, contained nonforfeitable rights to dividends and as such, were considered to be participating securities and are included in the computation of basic and diluted earnings per share, pursuant to the two-class method.

The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutivemodifications to net operating loss ~~per share~~limitations, business interest limitations and ~~conversion into common shares is assumed to~~alternative minimum tax. The CARES Act did not occur. Diluted net earnings (loss) per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented below.

The following table provides a reconciliation of net loss to preferred shareholders, common shareholders, and participating securities for purposes of computing net loss per share for the Predecessor Periods presented:

Three Months Ended

Nine Months Ended

September 30, 2016

September 30, 2016

(in thousands, except per
share amounts)

(in thousands, except per
share amounts)

Net loss

$
(38,384
)
$
(208,696
)
Preferred Dividend

—

—

Participating securities—non-vested restricted stock

—

—

Net loss attributable to shareholders

$
(38,384
)
$
(208,696
)

Weighted average shares outstanding

10,657

10,644

Basic and diluted net loss per share

$
(3.60
)
$
(19.61
)

~~13. Related Party Transactions~~

The Company has entered into an arrangement with EcoStim Energy Solutions, Inc. (“EcoStim”) for well stimulation and completion services. EcoStim is an affiliate of Fir Tree Inc., an entity holding approximately 25.5% of the Company’s outstanding common stock. For the three and nine months ended September 30, 2017, the Company paid approximately $5.9 million and $7.3 million, respectively, to EcoStim for services provided. No transactions with EcoStim occurred during the three and nine months ended September 30, 2016.

~~14. Commitments and Contingencies~~

The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws. Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices.

The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material ~~effect~~impact on ~~its results of operations. As of September 30, 2017, and December 31, 2016,~~ the Company’s ~~total accrual for all loss contingencies was $1.4 million and $1.1 million, respectively.~~current year tax provision.

During the nine months ended September 30, 2017, the Company received an insurance reimbursement in the amount of $1.9 million, which was reflected as a reduction of “Lease operating and workover” expenses in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2017.

~~15. Subsequent Event~~

On October 25, 2017, David J. Sambrooks was appointed to the position of President and Chief Executive Officer, effective immediately upon the resignation of Mr. Brace on November 1, 2017. The Board of Directors of the Company (the “Board”) also approved an increase in the number of directors, from seven directors to eight directors, and Mr. Sambrooks was appointed to the Board, effective concurrently with his appointment as an executive officer.

In connection with the appointment of Mr. Sambrooks as President and Chief Executive Officer, Mr. Sambrooks and the Company entered into an employment agreement outlining the terms of his employment as President and Chief Executive Officer of the Company. Among other provisions, Mr. Sambrooks received incentive awards including (i) the grant of 67,889 time-vested restricted stock units and (ii) the grant of 135,778 performance stock units (“PSUs”). The time-vested restricted stock units will generally vest in three installments: 1/3 will vest on the one-year anniversary of the award date, an additional 1/3 will vest on the two-year anniversary of the award date and the final 1/3 will vest on the three-year anniversary of the award date. The PSUs will vest, if at all, based upon the performance of the Company’s stock during the period of October 25, 2017 through October 31, 2020 (the “Performance Period”). Half of the PSUs will vest, if at all, based upon the Company’s total absolute stockholder return for the Performance Period, and the other half will vest, if at all, based upon the Company’s relative total stockholder return when measuring the Company’s stock performance during the Performance Period to the stock performance of a selected peer group during the Performance Period.

ITEM 2.

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

~~ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~The following discussion~~Management’s Discussion and ~~analysis~~Analysis of ~~our financial condition~~Financial Condition and ~~results~~Results of ~~operations~~Operations should be read in conjunction with ~~our consolidated financial statements~~the Unaudited Condensed Consolidated Financial Statements and accompanying notes ~~thereto for the year ended December 31, 2016,~~in “Item 1. Financial Statements” contained herein and ~~the related management’s discussion and analysis contained in~~ our Annual Report onthe Amplify Form 10-K dated and filed with the Securities and Exchange Commission (“SEC”) on March 30, 2017, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q ~~and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017.~~

~~CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS~~

~~Various statements contained in or incorporated by reference into this report are~~10-K. The following discussion contains forward-looking statements ~~within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”)~~that reflect our future plans, estimates, beliefs and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and the plans, beliefs, expectations, intentions and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Quarterly Report. You should not place undue reliance on these forward-looking statements. Theseexpected performance. The forward-looking statements are ~~subject to a number of~~dependent upon events, risks uncertainties and assumptions, including changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties ~~regarding environmental regulations or litigation and other legal or regulatory developments affecting~~that may be outside our business, as well as those factors discussed below and elsewhere in this report and in the Annual Report on Form 10-K. Moreover, we operate in a very competitive and rapidly changing environment. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, andcontrol. Our actual results could differ materially ~~and adversely~~ from those ~~anticipated or implied~~discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the ~~forward-looking statements.~~front of this report.

~~Forward-looking statements may include statements about our:~~

· ~~business strategy, including our business strategy post-emergence from our Chapter 11 Cases;~~

· ~~estimated future net reserves and present value thereof;~~

· ~~technology;~~

· ~~financial condition, revenues, cash flows and expenses;~~

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

· ~~financial strategy, budget, projections and operating results;~~

· ~~oil and natural gas realized prices;~~

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

· ~~availability of drilling and production equipment;~~

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

· ~~availability of oilfield labor;~~

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

· ~~availability and terms of capital;~~

· ~~drilling of wells, including our identified drilling locations;~~

· ~~successful results from our identified drilling locations;~~

· ~~marketing of oil and natural gas;~~

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

· ~~infrastructure for salt water disposal and electricity;~~

· ~~current and future ability to dispose of salt water;~~

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

· ~~costs of developing our properties and conducting other operations;~~

· ~~general economic conditions;~~

· ~~effectiveness of our risk management activities;~~

· ~~environmental liabilities;~~

· ~~counterparty credit risk;~~

· ~~the outcome of pending and future litigation;~~

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

· ~~developments in oil and natural gas producing countries;~~

· new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting;

· ~~uncertainty regarding our future operating results; and~~

· ~~plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.~~

Overview

We ~~are an independent exploration and production company focused on the application of modern drilling and completion techniques~~operate in oil and liquids-rich basins in the onshore United States. Our operations are primarily focused on exploration and production activities in the Mississippian Lime and Anadarko Basin. The terms “Company,” “we,” “us,” “our,” and similar terms refer to us and our subsidiary, unless the context indicates otherwise.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we realize from the sale of that production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, if any, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Upon our emergence from the Chapter 11 Cases on October 21, 2016, we adopted fresh start accounting as required by US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, our consolidated financial statements on or after October 21, 2016, are not comparable with our consolidated financial statements prior to that date. References to “Successor Period” relate to the results of operations for the period January 1, 2017 through September 30, 2017 and references to “Predecessor Period” refer to the results of operations of the Company from January 1, 2016 through September 30, 2016.

~~Operations Update~~

~~Mississippian Lime~~

~~For the three months ended September 30, 2017 and June 30, 2017, our average daily production from the Mississippian Lime asset was as follows:~~

Three Months Ended
September 30, 2017

Three Months Ended
June 30, 2017

Increase/(Decrease)
in Production

Average daily production:

Oil (Bbls)

4,940

4,938

—
%
Natural gas liquids (Bbls)

4,145

4,466

(7.2
)%
Natural gas (Mcf)

51,130

53,246

(4.0
)%
Net Boe/day

17,606

18,278

(3.7
)%

~~The following table shows our total number of horizontal wells spud and brought into production in the Mississippian Lime asset during the third quarter of 2017:~~

Total Number of
Gross Horizontal
Wells Spud (1)

Total Number of
Gross Horizontal
Wells Brought
into Production

Mississippian Lime

10

9

~~(1)~~ We had two rigs drilling in the Mississippian Lime horizontal well program at September 30, 2017. Of the ten wells spud, three were producing, five were awaiting completion and two were being drilled at quarter-end.

~~In the third quarter of 2017, we incurred approximately $39.8 million of operational capital expenditures in the Mississippian Lime basin.~~

~~Anadarko Basin~~

~~For the three months ended September 30, 2017 and June 30, 2017, our average daily production from our Anadarko Basin asset was as follows:~~

Three Months Ended
September 30, 2017

Three Months Ended
June 30, 2017

Decrease in
Production

Average daily production:

Oil (Bbls)

1,329

1,475

(9.9
)%
Natural gas liquids (Bbls)

992

1,115

(11.0
)%
Natural gas (Mcf)

8,581

9,735

(11.9
)%
Net Boe/day

3,752

4,212

(10.9
)%

~~We did not spud any wells in our Anadarko Basin asset and did not have any operated drilling rigs in the area during the third quarter of 2017.~~

~~Capital Expenditures~~

~~During the three and nine months ended September 30, 2017, we incurred operational capital expenditures of $40.1 million and $97.7 million, respectively, which consisted of the following:~~

For the Three
Months Ended
September 30, 2017

For the Nine
Months Ended
September 30, 2017

Drilling and completion activities

$
36,269

$
89,975

Acquisition of acreage and seismic data

3,845

7,748

Operational capital expenditures incurred

$
40,114

$
97,723

Capitalized G&A, office, ARO & other

1,856

5,512

Capitalized interest

408

2,054

Total capital expenditures incurred

$
42,378

$
105,289

~~Operational capital expenditures by area were as follows:~~

For the Three
Months Ended
September 30, 2017

For the Nine
Months Ended
September 30, 2017

Mississippian Lime

$
39,800

$
95,490

Anadarko Basin

314

2,233

Total operational capital expenditures incurred

$
40,114

$
97,723

We are currently operating two drilling rigs in the Mississippian Lime asset. Based upon a two rig program, we would expect to invest between $130.0 million to $140.0 million of capital for exploration, development and lease and seismic acquisition, and drill 36 to 40 gross wells during the year ended December 31, 2017.

~~Factors that Significantly Affect Our Risk~~

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

~~Like all businesses~~one reportable segment engaged in the ~~exploration~~acquisition, development, exploitation and production of oil and natural gas we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques.properties. Our ~~future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus~~management evaluates performance based on the ~~capital investments necessary to produce our reserves~~reportable business segment as ~~well as to add to our reserves through drilling and acquisition. Our ability to make~~ the ~~necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including~~economic environments are not different within the ~~cost and terms of such capital, our current financial condition, expectations regarding the future price for oil and natural gas, and operational considerations.~~

~~The volumes of oil and natural gas that we produce are driven by several factors, including:~~

· ~~success in the drilling of new wells, including exploratory wells, and the recompletion or workover of existing wells;~~

· ~~the amount of capital we invest in the leasing and development~~operation of our oil and natural gas ~~properties;~~

· ~~facility or equipment availability~~properties. Our business activities are conducted through OLLC our wholly owned subsidiary, and ~~unexpected downtime;~~

· ~~delays imposed by or resulting from compliance with regulatory requirements;~~

· ~~the rate at which production volumes on our wells naturally decline; and~~

· ~~our ability to economically dispose~~its wholly owned subsidiaries. Our assets consist primarily of ~~salt water produced in conjunction with our production of oil and gas.~~

We follow the full cost method of accounting for our oil and gas properties. For the three and nine months ended September 30, 2017, the results of our full cost “ceiling test” did not require us to recognize impairments of our oil and gas properties. While impairments do not impact cash flow from operating activities or liquidity, they do decrease our net income and shareholders’ equity.

~~We dispose of large volumes of saltwater produced in conjunction with crude~~producing oil and natural gas ~~from drilling~~properties and ~~production operations in the Mississippian Lime. Our disposal operations~~ are ~~conducted pursuant to permits issued to us by governmental authorities overseeing such disposal activities.~~

There is a continuing concern and regulatory scrutiny surrounding any potential correlation between the injection of saltwater into disposal wells and those activities alleged contribution to increased seismic activity in certain areas, including the areas in which we operate, Oklahoma and Texas. On February 16, 2016, the Oil and Gas Conservation Division (“OGCD”) of the Oklahoma Corporation Commission (“OCC”) requested we curtail our wastewater disposal volumes into the Arbuckle formation in our Mississippian Lime assets by approximately 40%. On March 7, 2016 and August 19, 2016, the OGCD identified additional wells that were required to reduce disposal volume. The OGCD established caps for additional wells on February 24, 2017. On March 1, 2017, the OGCD also issued a statement saying that further actions to reduce the earthquake ratelocated in Oklahoma, ~~could be expected. Our current plans are for future disposal wells to inject into formations other than~~ the ~~Arbuckle~~Rockies, in federal waters offshore Southern California, East Texas / North Louisiana and ~~we are currently disposing~~South Texas. Most of approximately 40% of our produced salt water into formations other than the Arbuckle. We have timely met and satisfied all requests of the OCC regarding changes and/or reductions in disposal capacity in our operated Arbuckle disposal wells, and now inject at a rate which is approximately 20% below the OGCD’s prescribed limits for the Arbuckle formation without adverse impact to our production base. We are currently in compliance with the OGCD’s latest requests regarding Arbuckle injection limits; however a change in disposal well regulations or injection limits, or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations and/or reduce the volume of oil and natural gas that we produce from our wells.

Under Rule 4-10(a)(22) of Regulation S-X, as promulgated by the SEC, proved reserves are those quantities of oil and natural gas, which, by 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. Our customary practice is at each fiscal year end our technical team meets with representatives of our independent reserves engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. We maintain an internal staff of petroleum engineers, land and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data utilized in the reserves estimation process. The primary inputs to the reserves estimation process are comprised of technical information, financial data, ownership interests and production data. The valuation of our proved reserves is sensitive to changes in these inputs and, as a result, minor updates to these inputs can result in significant changes in the valuation of such reserves. The extent of any such changes in reserves valuation is inherently uncertain until the final completion of the proved reserves estimates at each fiscal year end.

~~Results of Operations~~

~~The following tables summarize our revenues for the three and nine months ended September 30, 2017 and 2016 (in thousands):~~

Three Months Ended September 30,

Crude Oil

Natural Gas

NGLs

Total

2016 Revenues (Predecessor)

$
35,584

$
17,676

$
8,939

$
62,199

Changes due to volumes

(11,820
)
(3,776
)
(2,649
)
(18,245
)
Changes due to price

3,426

70

4,366

7,862

2017 Revenues (Successor)

$
27,190

$
13,970

$
10,656

$
51,816

Nine Months Ended September 30,

Crude Oil

Natural Gas

NGLs

Total

2016 Revenues (Predecessor)

$
104,832

$
44,486

$
25,073

$
174,391

Changes due to volumes

(48,583
)
(12,776
)
(6,717
)
(68,076
)
Changes due to price

29,248

14,611

13,224

57,083

2017 Revenues (Successor)

$
85,497

$
46,321

$
31,580

$
163,398

~~Oil, NGL and Natural Gas Pricing~~

~~The following table sets forth information regarding average realized sales prices for the periods indicated~~:

Successor

Predecessor

Successor

Predecessor

For the Three

For the Three

For the Nine

For the Nine

Months Ended

Months Ended

Months Ended

Months Ended

September 30,
2017

September 30,
2016

%
Change

September 30,
2017

September 30,
2016

%
Change

AVERAGE SALES PRICES:

Oil, without realized derivatives (per Bbl)

$
47.14

$
43.00

9.6
%
$
47.83

$
37.42

27.8
%
Oil, with realized derivatives (per Bbl)

$
50.11

$
43.00

16.5
%
$
50.09

$
37.42

33.9
%
Natural gas liquids, without realized derivatives (per Bbl)

$
22.55

$
15.15

48.8
%
$
21.17

$
13.86

52.7
%
Natural gas liquids, with realized derivatives (per Bbl)

$
22.55

$
15.15

48.8
%
$
21.17

$
13.86

52.7
%
Natural gas, without realized derivatives (per Mcf)

$
2.54

$
2.53

0.4
%
$
2.71

$
2.04

32.8
%
Natural gas, with realized derivatives (per Mcf)

$
2.76

$
2.53

9.1
%
$
2.83

$
2.04

38.7
%

~~Oil Revenues~~

~~Successor Period~~

Our oil sales revenues for the three and nine months ended September 30, 2017 were $27.2 million and $85.5 million, respectively. Our oil sales revenues were comprised of $21.6 million and $67.8 million, respectively, from our Mississippian Lime assets and $5.6 million and $17.7 million, respectively, from our Anadarko Basin assets.

~~Predecessor Period~~

Our oil sales revenues for the three and nine months ended September 30, 2016 were $35.6 million and $104.8 million, respectively. Our oil sales revenue was comprised of $29.0 million and $85.2 million, respectively, from our Mississippian Lime assets and $6.6 million and $19.6 million, respectively, from our Anadarko Basin assets.

~~Natural Gas Revenues~~

~~Successor Period~~

Our natural gas sales revenues for the three and nine months ended September 30, 2017 were $14.0 million and $46.3 million, respectively. Our natural gas sales revenues were comprised of $12.1 million and $40.0 million, respectively, from our Mississippian Lime assets and $1.9 million and $6.3 million, respectively, from our Anadarko Basin assets.

~~Predecessor Period~~

Our natural gas sales revenues for the three and nine months ended September 30, 2016 were $17.7 million and $44.5 million, respectively. Our natural gas sales revenue was comprised of $15.5 million and $39.3 million, respectively, from our Mississippian Lime assets and $2.2 million and $5.2 million, respectively, from our Anadarko Basin assets.

~~NGL Revenues~~

~~Successor Period~~

Our NGLs sales revenues for the three and nine months ended September 30, 2017 were $10.7 million and $31.6 million, respectively. Our NGLs sales revenues were comprised of $8.5 million and $25.4 million, respectively, from our Mississippian Lime assets and $2.2 million and $6.2 million, respectively, from our Anadarko Basin assets.

~~Predecessor Period~~

Our NGLs sales revenues for the three and nine months ended September 30, 2016 were $8.9 million and $25.1 million, respectively. Our NGLs sales revenue was comprised of $7.3 million and $20.5 million, respectively, from our Mississippian Lime assets and $1.6 million and $4.6 million, respectively, from our Anadarko Basin assets.

~~Gains (losses) on Commodity Derivative Contracts—Net~~

A summary of our open commodity derivative positions is included the financial statements in “Part I. Financial Information — Item 1. Financial Statements — Notes to the Unaudited Condensed Consolidated Financial Statements — Note 4. Risk Management and Derivative Instruments” of this report. The following tables provide financial information associated with our oil and natural gas ~~hedges~~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, 2019:

•

Our total estimated proved reserves were approximately 163.0 MBoe, of which approximately 43% were oil and 80% were classified as proved developed reserves;

•

We produced from 2,643 gross (1,567 net) producing wells across our properties, with an average working interest of 59% and the Company is the operator of record of the properties containing 93% of our total estimated proved reserves; and

•

Our average net production for the three months ended December 31, 2019 was 29.9 MBoe/d, implying a reserve-to-production ratio of approximately 15 years.

Industry Trends and Outlook

In March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the United States. The spread of COVID-19 has caused significant volatility in U.S. and international markets. There is significant uncertainty around the breadth and duration of business disruptions related to COVID-19, as well as its impact on the U.S. and international economies and, as such, the Company is unable to determine the extent of the impact caused by the COVID-19 pandemic to the Company’s operations.

In addition, oil prices severely declined following unsuccessful negotiations between members of OPEC and certain nonmembers, including Russia, to implement production cuts in an effort to decrease the global oversupply and to rebalance supply and demand due to the ongoing COVID-19 pandemic. In April 2020, members of OPEC and Russia agreed to temporary production reductions, but uncertainty about whether such production cuts and/or the duration of such reductions will be sufficient to rebalance supply and demand remains and may continue for the ~~period indicated (in thousands):~~foreseeable future. We anticipate further market and commodity price volatility for the remainder of 2020 as a result of the events described above.

For the Three
Months Ended
September 30, 2017

For the Nine
Months Ended
September 30, 2017

Cash settlements:

Oil derivatives

$
1,713

$
4,041

Natural gas derivatives

1,196

2,108

Total cash settlements

$
2,909

$
6,149

Gains (losses) due to fair value changes:

Oil derivatives

$
(5,618
)
$
925

Natural gas derivatives

(882
)
1,693

Total gains (losses) on fair value changes

$
(6,500
)
$
2,618

Gains (losses) on commodity derivative contracts—net

$
(3,591
)
$
8,767

~~Successor Period~~

~~During~~The reductions in commodity prices have resulted in lower levels of cash flow from operating activities. In addition, the ~~three~~borrowing base under our Revolving Credit Facility is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated oil, NGL and ~~nine months ended September 30, 2017, we had unrealized gains (losses)~~natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, adjusted for the impact of ~~$(6.5) million and $2.6 million from~~ our ~~mark-to-market~~commodity derivative ~~positions, representing the changes~~contracts. Severely reduced commodity prices contributed to a reduction in ~~fair value from new positions and settlements that occurred~~our borrowing base during the Spring 2020 determination process, and continued low prices may adversely impact subsequent redeterminations. The reduction in commodity prices has directly led to an impairment of our oil and natural gas properties. There may be further impairments in future periods if commodity prices remain depressed.

The Company has executed several significant initiatives to better position the Company through the downturn, including significant decreases to operating and general and administrative expenses, substantial reductions to capital programs, the monetization of a portion of the Company’s 2021 in-the-money crude oil hedges, the receipt of loan proceeds from the federal government PPP program, Beta royalty relief and the suspension of the quarterly dividend.

Recent Developments

Beta Royalty Relief

On, June 24, 2020, the Bureau of Safety and Environmental Enforcement (“BSEE”) informed the Company that it had been approved for the Special Case Royalty Relief for the Company’s interests in three Pacific Outer Continental Shelf blocks (P-300, P-0301, and P-0306), referred to as the Beta unit in the Beta Field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. The royalty relief was effective beginning July 1, 2020 for the Beta leases. On the Company’s two primary producing leases, the royalty rate was reduced from 25% to 12.5%, and on the third lease, the royalty rate was reduced from 16.67% to 8.33%.

The royalty relief rates will be suspended in months in which the weighted average NYMEX oil and Henry Hub gas price exceeds $66.19 per BOE which represents a 25% premium to the average realized price recognized by the Company during the qualification period. The royalty relief would end in the event that the Company generates no benefit from the royalty relief rates due to either higher production or realized pricing for 12 consecutive months.

Cure of Non-Compliance with NYSE Continued Listing Standards

On June 2, 2020, the Company received written notification from the NYSE that the Company regained compliance with the NYSE’s continued listing standards. The Company regained compliance after its average closing price for the 30 trading-day period ended May 29, 2020 and its closing price on May 29, 2020 both exceeded $1.00 per share. The “.BC” indicator has been removed from the Company’s common shares, and the Company was removed from the NYSE list of non-compliant issuers.

Departure of Director

Retirement of President, Chief Executive Officer and Director

Appointment of Interim Chief Executive Officer

Business Environment and Operational Focus

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

Sources of Revenues

Our revenues are derived from the sale of natural gas and oil production, as well as the ~~relationship between contract prices and the associated forward curves. Cash receipts~~sale of NGLs that are extracted from natural gas during processing. Production revenues are derived entirely from the ~~settlements of derivatives during the three~~continental United States. Natural gas, NGL and ~~nine months ended September 30, 2017 were $2.9 million~~oil prices are inherently volatile and ~~$6.1 million, respectively.~~

~~Predecessor Period~~

~~We had no open or settled commodity derivative positions during the three and nine months ended September 30, 2016.~~

~~Oil, Natural Gas and NGL Production~~

Successor

Predecessor

Successor

Predecessor

For the Three
Months Ended

For the Three
Months Ended

For the Nine
Months Ended

For the Nine
Months Ended

September
30, 2017

September
30, 2016

%
Change

September
30, 2017

September
30, 2016

%
Change

PRODUCTION DATA:

Oil (Bbls/d)

Mississippian Lime

4,940

7,266

(32.0
)%
5,158

8,279

(37.7
)%
Anadarko Basin

1,329

1,728

(23.1
)%
1,389

1,947

(28.7
)%
Natural gas liquids (Bbls/d)

Mississippian Lime

4,145

5,209

(20.4
)%
4,398

5,350

(17.8
)%
Anadarko Basin

992

1,204

(17.6
)%
1,066

1,250

(14.7
)%
Natural gas (Mcf/d)

Mississippian Lime

51,130

65,287

(21.7
)%
53,474

68,612

(22.1
)%
Anadarko Basin

8,581

10,624

(19.2
)%
9,225

10,872

(15.1
)%
Combined (Boe/d)

Mississippian Lime

17,606

23,357

(24.6
)%
18,469

25,065

(26.3
)%
Anadarko Basin

3,752

4,702

(20.2
)%
3,993

5,008

(20.3
)%

~~Commodity production for the three and nine months ended September 30, 2017 is lower compared~~are influenced by many factors outside our control. In order to ~~the three and nine months ended September 30, 2016 due to natural decline and a lower level of drilling activity during the 2017 period.~~

~~Expenses~~

Successor

Predecessor

Successor

Predecessor

Successor

Predecessor

Successor

Predecessor

Three Months Ended
September 30,

Three Months Ended
September 30,

Nine Months Ended
September 30,

Nine Months Ended
September 30,

2017

2016

2017

2016

2017

2016

2017

2016

(in thousands)

(per Boe)

(in thousands)

(per Boe)

EXPENSES:

Lease operating and workover

$
15,653

$
17,650

$
7.97

$
6.84

$
48,064

$
49,520

$
7.84

$
6.01

Gathering and transportation

3,699

4,296

1.88

1.66

11,027

13,428

1.80

1.63

Severance and other taxes

2,352

1,788

1.20

0.69

6,168

4,776

1.01

0.58

Asset retirement accretion

274

452

0.14

0.17

833

1,316

0.14

0.16

Depreciation, depletion, and amortization

15,170

15,756

7.72

6.10

46,471

59,229

7.58

7.19

Impairment of oil and gas properties

—

33,887

—

13.13

—

224,584

—

27.26

General and administrative

7,255

3,308

3.69

1.27

23,102

19,093

3.77

2.32

Debt restructuring costs and advisory fees

—

—

—

—

—

7,589

—

0.92

Total expenses

$
44,403

$
77,137

$
22.60

$
29.86

$
135,665

$
379,535

$
22.14

$
46.07

~~Lease Operating and Workover~~

~~Successor Period~~

Our lease operating and workover expenses for the three and nine months ended September 30, 2017 were $15.7 million and $48.1 million, respectively. Lease operating and workover expenses were $7.97 and $7.84 per Boe, respectively. As previously discussed in “Part I. Financial Information — Item 1. Financial Statements — Notes to the Unaudited Condensed Consolidated Financial Statements — Note 14. Commitments and Contingencies”, lease operating and workover expenses were positively impacted during the nine months ended September 30, 2017 by a $1.9 million reimbursement received for an insurance claim.

~~Predecessor Period~~

Our lease operating and workover expenses for the three and nine months ended September 30, 2016 were $17.7 million and $49.5 million, respectively. Lease operating and workover expenses were $6.84 and $6.01 per Boe, respectively.

~~Gathering and Transportation~~

~~Successor Period~~

Our gathering and transportation expenses for the three and nine months ended September 30, 2017 were $3.7 million and $11.0 million, respectively. Gathering and transportation expenses were $1.88 and $1.80 per Boe, respectively.

~~Predecessor Period~~

Our gathering and transportation expenses for the three and nine months ended September 30, 2016 were $4.3 million and $13.4 million, respectively. Gathering and transportation expenses were $1.66 and $1.63 per Boe, respectively.

~~Severance and Other Taxes~~

Successor

Predecessor

Successor

Predecessor

Three Months Ended

Three Months Ended

Nine Months Ended

Nine Months Ended

September 30, 2017

September 30, 2016

September 30, 2017

September 30, 2016

(in thousands)

(in thousands)

(in thousands)

(in thousands)

Total oil, natural gas, and natural gas liquids sales

$
51,816

$
62,199

$
163,398

$
174,391

Severance taxes

2,128

1,353

5,496

3,717

Ad valorem and other taxes

224

435

672

1,059

Severance and other taxes

$
2,352

$
1,788

$
6,168

$
4,776

Severance taxes as a percentage of sales

4.1
%

2.2
%
3.4
%

2.1
%
Severance and other taxes as a percentage of sales

4.5
%

2.9
%
3.8
%

2.7
%

~~Successor Period~~

Our severance and other tax expenses for the three and nine months ended September 30, 2017 were $2.4 million or 4.5% of sales and $6.2 million or 3.8% of sales, respectively. Severance tax for the three and nine months ended September 30, 2017 was $2.1 million or 4.1% of sales and $5.5 million or 3.4% of sales, respectively.

Prior to July 1, 2017, the State of Oklahoma had a crude oil and natural gas production tax incentive for wells that commenced production between July 1, 2011 and July 1, 2015, which allowed for a 1.0% production tax rate for the first 48 months of production. In May 2017, new legislation was signed into law in Oklahoma that increased the incentive tax rate from 1.0% to 4.0% on those wells. After the 48 month incentive period ends, the tax rate on such wells increases to 7.0%. The new 4.0% tax rate on these wells went into effect on July 1, 2017 and caused our average production tax rate to trend higher in the three months ended September 30, 2017. Whilereduce the impact of ~~increased production taxes is uncertain, based upon our current production,~~fluctuations in natural gas and oil prices on revenues, we ~~estimate~~intend to periodically enter into derivative contracts that fix the ~~elimination~~future prices received. At the end of each period the fair value of these ~~tax incentive wells will increase monthly production taxes by approximately $0.2 million.~~

~~Predecessor Period~~

~~Our severance~~commodity derivative instruments are estimated and ~~other tax expenses for~~because hedge accounting is not elected, the ~~three and nine months ended September 30, 2016 were $1.8 million or 2.9%~~changes in the fair value of sales and $4.8 million or 2.7% of sales, respectively. Severance tax for the three and nine months ended September 30, 2016 was $1.4 million or 2.2% of sales and $3.7 million or 2.1% of sales, respectively.

~~Depreciation, Depletion and Amortization (“DD&A”)~~

~~Successor Period~~

~~Our DD&A expenses for the three and nine months ended September 30, 2017 were $15.2 million at a cost of $7.72 per Boe and $46.5 million at a cost of $7.58 per Boe, respectively.~~

~~Predecessor Period~~

~~Our DD&A expenses for the three and nine months ended September 30, 2016 were $15.8 million at a cost of $6.10 per Boe and $59.2 million at a cost of $7.19 per Boe, respectively.~~

~~Impairment of Oil and Gas Properties~~

~~Successor Period~~

~~We did not incur any impairments of oil and gas properties during the three or nine months ended September 30, 2017.~~

~~Predecessor Period~~

~~Our impairment of oil and gas properties for the three and nine months ended September 30, 2016 was $33.9 million and $224.6 million, respectively. The impairment expense~~unsettled commodity derivative instruments are recognized in the Predecessor Period was primarily due to a decrease in the PV-10 value of our proven oil and natural gas reserves as a result of continued low commodity prices, which are a significant input into the calculation of the discounted future cash flows associated with our proved oil and gas reserves.

~~General and Administrative (“G&A”)~~

~~Successor Period~~

Our G&A expense for the three and nine months ended September 30, 2017 was $7.3 million at a cost of $3.69 per Boe and $23.1 million at a cost of $3.77 per Boe, respectively. G&A for the three and nine months ended September 30, 2017 was impacted by non-cash stock based compensation expense for awards issued pursuant to the 2016 LTIP of $2.8 million and $7.1 million, respectively, as well as trailing costs incurred related to the Chapter 11 Cases of $0.1 million and $2.7 million, respectively.

~~Predecessor Period~~

Our G&A expense for the three and nine months ended September 30, 2016 was $3.3 million at a cost of $1.27 per Boe and $19.1 million at a cost of $2.32 per Boe, respectively. G&A for the nine months ended September 30, 2016 included the acceleration of rent and related expenses associated with the Houston office lease abandonment totaling $2.5 million.

~~Debt Restructuring Costs and Advisory Fees~~

~~Successor Period~~

We did not incur any debt restructuring costs or advisory fees during the three or nine months ended September 30, 2017. Trailing costs associated with the Chapter 11 Cases incurred subsequent to the Emergence Date are included in G&A expense, as discussed above.

~~Predecessor Period~~

For the nine months ended September 30, 2016 we incurred $7.6 million of advisory fees to assist with analyzing various strategic alternatives to address our liquidity and capital structure. Costs associated with the Chapter 11 Cases incurred subsequent to April 30, 2016 were included in reorganization items, net, as discussed below.

~~Other Expense~~

~~Interest Expense~~

~~Successor Period~~

Interest expense for the three and nine months ended September 30, 2017 was $1.9 million and $5.6 million, respectively. Interest expense related to our Exit Facility bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. For the three months ended September 30, 2017, the weighted average interest rate was 5.7%. We also capitalized $0.4 million and $2.1 million, respectively, of interest expense to our unproved oil and gas properties during the three and nine months ended September 30, 2017.

~~Predecessor Period~~

Our interest expense for the three and nine months ended September 30, 2016 was $2.7 million and $74.0 million, respectively. During the three and nine months ended September 30, 2016, interest expense ceased for all debt except amounts outstanding under the credit facility beginningearnings at the ~~petition date~~end of April 30, 2016. During the nine months ended September 30, 2016, interest expense was offset by $8.2 million related to the amortization of the deferred gain on extinguished debt. No interest expense was capitalized for the three and nine months ended September 30, 2016, due to the transfer of all balances related to unproved properties to the full cost pool at December 31, 2015.

~~Provision for Income Taxes~~

~~Successor Period~~

We recorded no income tax expense or benefit due to the change in our valuation allowance recorded against our net deferred tax assets. Our valuation allowance decreased by $13.0 million from December 31, 2016 bringing our total valuation allowance to $147.8 million at September 30, 2017.

~~Predecessor Period~~

We recorded no income tax expense or benefit. During the nine months ended September 30, 2016, we recorded $70.9 million in additional valuation allowance, bringing the total valuation allowance to $766.0 million at September 30, 2016.

~~Reorganization Items, Net~~

~~Successor Period~~

~~We did not incur any reorganization items during the three or nine months ended September 30, 2017.~~

~~Predecessor Period~~

We recognized a net loss of $(22.8) million and a net gain of $57.8 million in reorganization items, net during the three and nine months ended September 30, 2016, respectively. Reorganization items, net represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated.

~~Liquidity and Capital Resources~~

~~Overview~~

~~The following table presents a summary of our key financial indicators at the dates presented (in thousands):~~

September 30, 2017

December 31, 2016

Cash and cash equivalents

$
76,548

$
76,838

Net working capital

58,397

67,637

Total long-term debt

128,059

128,059

Total stockholders’ equity

605,597

561,814

Available borrowing capacity

40,000

—

~~Our decisions regarding capital structure, hedging and drilling are based upon many factors, including anticipated future commodity pricing, expected economic conditions and recoverable reserves.~~

We anticipate our operating cash flows and cash on hand will be our primary sources of liquidity although we may seek to supplement our liquidity through divestitures, additional borrowings or debt or equity securities offerings as circumstances and market conditions dictate. We believe the combination of these sources of liquidity will be adequate to fund anticipated capital expenditures, service our existing debt and remain compliant with all other contractual commitments.

Our cash flows from operations are impacted by various factors, the most significant of which is the market pricing for oil, NGLs and natural gas. The pricing for these commodities is volatile, and the factors that impact such market pricing are global and therefore outside of our control. As a result, it is not possible for us to precisely predict our future cash flows from operating revenues due to these market forces.

We enter into hedging activities with respect to a portion of our production to manage our exposure to oil, NGLs and natural gas price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.

Consistent with our comprehensive growth strategy of focusing on a portfolio of core assets capable of supporting a long-term, sustainable drilling program, we are actively considering more substantial divestitures and other asset monetization transactions with respect to assets that we do not believe meet our strategic objectives. These transactions may involve significant asset positions, entire business units or corporate level transactions. Depending upon the success, timing and structure of any such transactions, the amount of proceeds we receive from portfolio management activity could materially increase during the remainder of 2017. In conjunction with our consideration of more substantial divestitures, we are also considering substantial acquisitions or other business combinations that further our comprehensive growth strategy.

~~Significant Sources of Capital~~

~~Exit Facility~~

At September 30, 2017, in addition to cash on hand of $76.5 million, we maintained the Exit Facility. The Exit Facility has a current borrowing base of $170.0 million. At September 30, 2017, we had $128.1 million drawn on the Exit Facility and outstanding letters of credit obligations totaling $1.9 million. As of September 30, 2017, we had $40.0 million of availability on the Exit Facility.

~~The Exit Facility bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. For the three months ended September 30, 2017, the weighted average interest rate was 5.7%.~~

~~In addition to interest expense, the Exit Facility requires the payment of a commitment fee~~ each ~~quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter.~~accounting period.

On May 24, 2017, we entered into the First Amendment to the Exit Facility. The First Amendment, among other items, (i) moved the first scheduled borrowing base redetermination from April 2018 to October 2017; (ii) removed the requirement to maintain a cash collateral account with the administrative agent in the amount of $40.0 million; (iii) removed the requirement to maintain at least 20% liquidity of the then effective borrowing base; (iv) amended the required mortgage threshold from 95% to 90%; (v) amended the threshold amount for which the borrower is required to provide advance notice to the administrative agent of a sale or disposition of oil and gas properties which occurs during the period between two successive redeterminations of the borrowing base; (vi) amended the required ratio of total net indebtedness to EBITDA from 2.25:1.00 to 4.00:1.00; (vii) amended the required EBITDA to interest coverage ratio from not less than 3.00:1.00 to not less than 2.50:1.00; and (viii) removed certain limitations on capital expenditures.

~~As of September 30, 2017, we were in compliance with our debt covenants.~~

On October 27, 2017, the Company’s borrowing base was redetermined at the existing amount of $170.0 million. Our Anadarko Basin assets in Texas and Oklahoma were excluded from the redetermination of the borrowing base.

~~Cash Flows from Operating, Investing and Financing Activities~~

The following table summarizes our condensed consolidated cash flows from operating, investing and financing activities for the periods presented. For information regarding the individual components of our cash flow amounts, please refer to the unaudited condensed consolidated statements of cash flows included under “Part I. Financial Information — Item 1. Financial Statements”of this Quarterly Report.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Part I. Financial Information — Item 3. Quantitative and Qualitative Disclosures about Market Risk.”

~~The following information highlights the significant period-to-period variances in our cash flow amounts (in thousands):~~

Successor

Predecessor

For the Nine Months
Ended September 30, 2017

For the Nine Months
Ended September 30, 2016

Net cash provided by operating activities

$
89,317

$
78,244

Net cash used in investing activities

(88,606
)

(129,072
)
Net cash (used in) provided by financing activities

(1,001
)

249,331

Net change in cash

$
(290
)

$
198,503

~~Cash flows provided by operating activities~~

~~Net cash provided by operating activities was $89.3 million and $78.2 million for the nine months ended September 30, 2017 and 2016, respectively.~~

~~Cash flows used in investing activities~~

We had net cash used in investing activities of $88.6 million and $129.1 million for the nine months ended September 30, 2017 and 2016, respectively. Net cash used in investing activities for the Successor Period and Predecessor Period primarily represents cash invested in oil and gas property and equipment.

~~Cash flows (used in) provided by financing activities~~

We had net cash used in financing activities for the nine months ended September 30, 2017, of $1.0 million and net cash provided by financing activities for the nine months ended September 30, 2016, of $249.3 million. Net cash used in financing activity for the Successor Period relates to deferred financing costs and the acquisition of treasury stock. Net cash provided by financing activities for the Predecessor Period primarily represents borrowings from the revolving credit facility of $249.4 million.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in the Amplify 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 ~~Annual Report on Form 10-K for~~opinion, are subjective in nature, require the ~~year ended December 31, 2016. There have been no material changes to those policies.~~ use of professional judgment and involve complex analysis.

When used in the preparation of our ~~unaudited condensed~~ 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 ~~unaudited condensed~~ consolidated financial position, results of operations and cash flows.

Results of Operations

~~Other Items~~The results of operations for the three and six months ended June 30, 2020 and 2019 have been derived from our consolidated financial statements. The following table summarizes certain of the results of operations for the periods indicated.

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
	($ In thousands)
Oil and natural gas sales	$	34,888		$	59,485		$	92,675		$	124,552
Lease operating expense		27,828			26,292			63,551			55,202
Gathering, processing and transportation		4,689			4,391			9,742			9,048
Taxes other than income		2,195			3,464			6,181			7,873
Depreciation, depletion and amortization		7,623			12,913			23,179			24,079
Impairment expense		—			—			455,031			—
General and administrative expense		6,755			10,566			15,108			19,874
Accretion of asset retirement obligations		1,539			1,332			3,052			2,643
(Gain) loss on commodity derivative instruments		19,165			(22,993	)		(88,548	)		9,494
Interest expense, net		(6,209	)		(4,422	)		(13,856	)		(8,511	)
Reorganization items, net		(166	)		(464	)		(352	)		(651	)
Income tax benefit (expense)		(85	)		—			(85	)		50
Net income (loss)		(41,336	)		18,641			(408,535	)		(12,836	)

Oil and natural gas revenue:
Oil sales	$	22,963		$	41,685		$	64,814		$	81,742
NGL sales		3,343			5,336			8,465			11,201
Natural gas sales		8,582			12,464			19,396			31,609
Total oil and natural gas revenue	$	34,888		$	59,485		$	92,675		$	124,552

Production volumes:
Oil (MBbls)		945			696			1,927			1,448
NGLs (MBbls)		435			258			889			524
Natural gas (MMcf)		6,857			5,803			14,443			11,293
Total (MBoe)		2,523			1,921			5,223			3,854
Average net production (MBoe/d)		27.7			21.1			28.7			21.3

Average sales price:
Oil (per Bbl)	$	24.30		$	59.85		$	33.64		$	56.44
NGL (per Bbl)		7.68			20.65			9.52			21.38
Natural gas (per Mcf)		1.25			2.15			1.34			2.80
Total (per Boe)	$	13.83		$	30.95		$	17.74		$	32.32

Average unit costs per Boe:
Lease operating expense	$	11.03		$	13.69		$	12.17		$	14.32
Gathering, processing and transportation		1.86			2.29			1.87			2.35
Taxes other than income		0.87			1.80			1.18			2.04
General and administrative expense		2.68			5.50			2.89			5.16
Depletion, depreciation and amortization		3.02			6.72			4.44			6.25

For the three months ended June 30, 2020 compared to the three months ended June 30, 2019

Net loss of $41.3 million and net income of $18.6 million were recorded for the three months ended June 30, 2020 and 2019, respectively.

Oil, natural gas and NGL revenues were $34.9 million and $59.5 million for the three months ended June 30, 2020 and 2019, respectively. Average net production volumes were approximately 27.7 MBoe/d and 21.1 MBoe/d for the three months ended June 30, 2020 and 2019, respectively. The increase in production volumes was primarily due to the Merger. The average realized sales price was $13.83 per Boe and $30.95 per Boe for the three months ended June 30, 2020 and 2019, respectively. The decrease in average realized sales price is primarily due to decrease in commodity prices. The overall decrease in revenue is due to a decline in well activity and a decrease in commodity pricing offset by additional volumes related to the Merger.

~~Obligations~~Lease operating expense was $27.8 million and ~~Commitments~~$26.3 million for the three months ended June 30, 2020 and 2019, respectively. The change in lease operating expense was primarily related to the Merger. On a per Boe basis, lease operating expense was $11.03 and $13.69 for the three months ended June 30, 2020 and 2019, respectively. The change on a per Boe basis is related to decreased drilling activities, cost savings initiatives implemented during the quarter and an increase in production due to the Merger.

Gathering, processing and transportation was $4.7 million and $4.4 million for the three months ended June 30, 2020 and 2019, respectively. The increase in gathering, processing and transportation was primarily driven by the Merger. On a per Boe basis, gathering, processing and transportation was $1.86 and $2.29 for the three months ended June 30, 2020 and 2019, respectively. The change on a per Boe basis was primarily due to increased production related to the Merger.

Taxes other than income was $2.2 million and $3.5 million for the three months ended June 30, 2020 and 2019, respectively. On a per Boe basis, taxes other than income were $0.87 and $1.80 for the three months ended June 30, 2020 and 2019, respectively. The change in taxes other than income on a per Boe basis was primarily due to a decrease in commodity prices.

Depreciation, depletion and amortization (“DD&A expense”) was $7.6 million and $12.9 million for the three months ended June 30, 2020 and 2019, respectively. The change in DD&A expense is primarily due to the first quarter 2020 impairment which reduced depletable oil and gas property. The decrease was also impacted by the Merger and lower production.

General and administrative expense was $6.8 million and $10.6 million for the three months ended June 30, 2020 and 2019, respectively. The change in general and administrative expense is primarily related to a decrease in acquisition expense of $3.4 million and a decrease in stock compensation expense of $0.9 million due to the revaluation of post-merger expense.

Net losses on commodity derivative instruments of $19.2 million were recognized for the three months ended June 30, 2020, consisting of $64.4 million decrease in the fair value of open positions offset by $27.3 million of cash settlements received on expired positions and $18.0 million of cash settlements received on terminated positions. Net gains on commodity derivative instruments of $23.0 million were recognized for the three months ended June 30, 2019, consisting of $23.6 million increase in fair value of open positions and offset by $0.6 million of cash settlements paid 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 $6.2 million and $4.4 million for the three months ended June 30, 2020 and 2019, respectively. Interest expense included a $2.7 million and $0.3 million in the amortization and write-off of deferred financing fees for the three months ended June 30, 2020 and 2019, respectively. Losses incurred on interest rate swaps was approximately $0.4 million and $0.6 million for the three months ended June 30, 2020 and 2019, respectively.

Average outstanding borrowings under our Revolving Credit Facility were $287.5 million and $259.3 million for the three months ended June 30, 2020 and 2019, respectively.

For the six months ended June 30, 2020 compared to the six months ended June 30, 2019

Net losses of $408.5 million and $12.8 million were recorded for the six months ended June 30, 2020 and 2019, respectively.

Oil, natural gas and NGL revenues were $92.7 million and $124.6 million for the six months ended June 30, 2020 and 2019, respectively. Average net production volumes were approximately 28.7 MBoe/d and 21.3 MBoe/d for the six months ended June 30, 2020 and 2019, respectively. The change in production volumes was primarily due to the Merger offset with the natural decline of wells and decreased drilling activity. The average realized sales price was $17.74 per Boe and $32.32 per Boe for the six months ended June 30, 2020 and 2019, respectively. The decrease in average realized sales price is primarily due to decrease in commodity prices. The overall decrease in revenue is due to a decline in well activity and a decrease in commodity pricing offset by additional volumes related to the Merger.

Lease operating expense was $63.6 million and $55.2 million for the six months ended June 30, 2020 and 2019, respectively. The change in lease operating expense was primarily related to the Merger. On a per Boe basis, lease operating expense was $12.17 and $14.32 for the six months ended June 30, 2020 and 2019, respectively. The change on a per Boe basis is related to decreased drilling activities, cost savings initiatives implemented during the quarter and an increase in production due to the Merger.

Gathering, processing and transportation was $9.7 million and $9.0 million for the six months ended June 30, 2020 and 2019, respectively. The increase in gathering, processing and transportation was primarily driven by the Merger. On a per Boe basis, gathering, processing and transportation was $1.87 and $2.35 for the six months ended June 30, 2020 and 2019, respectively. The change on a per Boe basis was primarily due to increased production related to the Merger.

Taxes other than income was $6.2 million and $7.9 million for the six months ended June 30, 2020 and 2019, respectively. On a per Boe basis, taxes other than income were $1.18 and $2.04 for the six months ended June 30, 2020 and 2019, respectively. The change in taxes other than income on a per Boe basis was primarily due to a decrease in commodity prices.

DD&A expense was $23.2 million and $24.1 million for the six months ended June 30, 2020 and 2019, respectively. The change in DD&A expense was primarily due to the first quarter impairment which reduced depletable oil and gas property.

Impairment expense was $455.0 million for the six months ended June 30, 2020. We recognized $405.7 million of impairment expense on proved properties. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. We recognized $49.3 million of impairment expense on unproved properties, which was related to expiring leases and the evaluation of qualitative and quantitative factors related to the current decline in commodity prices. No impairment expense was recorded for the six months ended June 30, 2019.

General and administrative expense was $15.1 million and $19.9 million for the six months ended June 30, 2020 and 2019, respectively. The change in general and administrative expense is primarily related to a decrease of $3.3 million in acquisition costs and a decrease of stock compensation expense of $1.9 million.

Net gains on commodity derivative instruments of $88.5 million were recognized for the six months ended June 30, 2020, consisting of $30.8 million increase in the fair value of open positions, $39.8 million of cash settlements paid on expired positions and $18.0 million of cash settlements received on terminated positions. Net losses on commodity derivative instruments of $9.5 million were recognized for the six months ended June 30, 2019, consisting of $7.6 million decrease in the fair value of open positions and $1.9 million of cash settlement receipts on expired positions.

Interest expense, net was $13.9 million and $8.5 million for the six months ended June 30, 2020 and 2019, respectively. The change in interest expense is primarily due to a $1.5 million reduction in interest expense due to lower outstanding borrowings for the six months ended June 30, 2020. The Company had $3.0 million and $0.6 million in amortization and write-off of deferred financing fees for the six months ended June 30, 2020 and 2019, respectively. In addition we had losses on interest rate swaps of approximately $4.1 million and $0.5 million for the six months ended June 30, 2020 and 2019 respectively.

Average outstanding borrowings under our Revolving Credit Facility were $291.3 million and $268.6 million for the six months ended June 30, 2020 and 2019, respectively.

Adjusted EBITDA

We ~~have various contractual obligations for~~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 ~~leases, including drilling contracts,~~activities, our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

•

Interest expense;

•

Income tax expense;

•

DD&A;

•

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

•

Accretion of AROs;

•

Loss on commodity derivative instruments;

•

Cash settlements received on expired commodity derivative instruments;

•

Losses on sale of assets;

•

Share/unit-based compensation expenses;

•

Exploration costs;

•

Acquisition and divestiture related expenses;

•

Restructuring related costs;

•

Reorganization items, net;

•

Severance payments; and

•

Other non-routine items that we deem appropriate.

Less:

•

Interest income;

•

Income tax benefit;

•

Gain on commodity derivative instruments;

•

Cash settlements paid on expired commodity derivative instruments;

•

Gains on sale of assets and other, net; and

•

Other non-routine items that we deem appropriate.

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

Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as ~~lease commitments~~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 ~~commitments~~may also be used by investors to measure our ability to meet debt service requirements.

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

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

Reconciliation of Adjusted EBITDA to Net Income (Loss)

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
	(In thousands)
Net loss	$	(41,336	)	$	18,641		$	(408,535	)	$	(12,836	)
Interest expense, net		6,209			4,422			13,856			8,511
Income tax expense (benefit)		85			—			85			(50	)
DD&A		7,623			12,913			23,179			24,079
Impairment expense		—			—			455,031			—
Accretion of AROs		1,539			1,332			3,052			2,643
(Gains) losses on commodity derivative instruments		19,165			(22,993	)		(88,548	)		9,494
Cash settlements received (paid) on expired commodity derivative instruments		27,295			(631	)		39,795			(1,908	)
Acquisition and divestiture related expenses		44			3,458			525			3,822
Share-based compensation expense		371			1,375			(540	)		3,311
Exploration costs		3			6			19			21
(Gain) loss on settlement of AROs		—			34			—			177
Bad debt expense		141			—			251			101
Reorganization items, net		166			464			352			651
Severance payments		10			50			29			89
Adjusted EBITDA	$	21,315		$	19,071		$	38,551		$	38,105

Reconciliation of Adjusted EBITDA to Net Cash from Operating Activities

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
	(In thousands)
Net cash provided by operating activities	$	29,900		$	22,499		$	42,989		$	33,299
Changes in working capital		5,766			(10,862	)		5,311			(7,856	)
Interest expense, net		6,209			4,422			13,856			8,511
Gain (loss) on interest rate swaps		(438	)		(578	)		(4,055	)		(484	)
Cash settlements paid (received) on interest rate swaps		346			(45	)		324			(45	)
Cash settlements paid (received) on terminated derivatives		(17,977	)		—			(17,977	)		—
Amortization and write-off of deferred financing fees		(2,690	)		(266	)		(2,999	)		(574	)
Acquisition and divestiture related expenses		44			3,458			525			3,822
Income tax expense (benefit) - current portion		85			—			85			(50	)
Exploration costs		3			6			19			21
Plugging and abandonment cost		—			77			—			382
Reorganization items, net		166			464			352			651
Severance payments		10			50			29			89
Other		(109	)		(154	)		92			339
Adjusted EBITDA	$	21,315		$	19,071		$	38,551		$	38,105

Liquidity and Capital Resources

Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, meet our indebtedness obligations, refinance our indebtedness or meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities and borrowings under our ~~Exit~~Revolving Credit Facility. ~~Information regarding these various obligations~~For the remainder of 2020, we expect our primary funding sources to be cash flows generated by operating activities and ~~commitments~~available borrowing capacity under our 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 ~~included~~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 30% - 60% 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 ~~Annual Report on Form 10-K~~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 June 30, 2020, 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 $22.2 million for the ~~year~~six months ended ~~December 31, 2016. There~~June 30, 2020, which were primarily related to capital workovers and facilities located in Oklahoma and California and non-operated drilling activities in South Texas.

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 June 30, 2020, we had working capital of $18.0 million primarily due to being in a receivable position with our short-term derivatives of $32.2 million, accounts receivable of $27.1 million, cash of $13.2 million and prepaid expenses of $12.2 million, offset by revenues payable of $22.5 million, current portion of long-term debt of $20.0 million, accrued liabilities of $17.8 million, and accounts payable of $5.6 million.

Debt Agreements

Revolving Credit Facility. On November 2, 2018, OLLC as borrower, entered into the Revolving Credit Facility (as amended and supplemented to date) with Bank of Montreal, as administrative agent. At June 30, 2020, our borrowing base under our 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 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 June 12, 2020, the Company entered into the Third Amendment; which, among other things, decreased the borrowing base from $450.0 million to $285.0 million, with monthly reductions of $5.0 million thereafter until the borrowing base is reduced to $260.0 million, effective November 1, 2020. The borrowing base as of June 30, 2020, was $285.0 million.

As of June 30, 2020, we were in compliance with all the financial (current ratio and total leverage ratio) and other covenants associated with our Revolving Credit Facility.

As of June 30, 2020, we had approximately $5.0 million of available borrowings under our Revolving Credit Facility. 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 our Revolving Credit Facility.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the six months ended June 30, 2020 and 2019, 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.

	For the Six Months Ended
	June 30,
	2020			2019
	(In thousands)
Net cash provided by operating activities	$	42,989		$	33,299
Net cash provided by (used in) investing activities		(26,842	)		56,425
Net cash used in financing activities		(3,270	)		(120,726	)

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $43.0 million and $33.3 million for the six months ended June 30, 2020 and 2019, respectively. Production volumes were approximately 28.7 MBoe/d and 21.3 MBoe/d for the six months ended June 30, 2020 and 2019, respectively. The average realized sales prices were $17.74 per Boe and $32.32 per Boe for the six months ended June 30, 2020 and 2019, respectively. Lease operating expenses were $63.6 million and $55.2 million for the six months ended June 30, 2020 and 2019, respectively. Gathering, processing and transportation was $9.7 million and $9.0 million for the six months ended June 30, 2020 and 2019, respectively.

Net cash provided by operating activities for the six months ended June 30, 2020 included $39.8 million of cash receipts on expired derivative instruments and $18.0 million of cash receipts on terminated derivative instruments compared to $1.9 million of cash paid on expired derivatives for the six months ended June 30, 2019. For the six months ended June 30, 2020, we had net gains on derivative instruments of $88.5 million compared to a net loss of $9.5 million for the six months ended June 30, 2019.

Investing Activities. Net cash provided by investing activities for the six months ended June 30, 2020 was $26.8 million, of which $26.1 million was used for additions to oil and natural gas properties. Net cash used in investing activities for the six months ended June 30, 2019 was $56.4 million, of which $33.2 million was used for additions to oil and natural gas properties. Withdrawal of restricted investments was $90.0 million, which related to the Company receiving $90.0 million from the Beta decommissioning trust account for the six months ended June 30, 2019.

Financing Activities. The Company had net repayments of $5.0 million and $119.0 million for the six months ended June 30, 2020 and 2019, respectively, related to our Revolving Credit Facility. The Company received a $5.5 million loan under the Paycheck Protection Program on April 24, 2020.

On March 3, 2020, our board of directors declared a dividend of $0.10 per share on our outstanding common stock, which was paid on March 30, 2020 to stockholders of record at the close of business on March 16, 2020.

Contractual Obligations

During the six months ended June 30, 2020, there were no significant changes in ~~these~~our consolidated contractual obligations ~~and commitments.~~

~~Off-Balance Sheet Arrangements~~

~~We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity and capital resource positions or for any other purpose. However, as is customary~~from those reported in the ~~oil~~Amplify Form 10-K except for the Revolving Credit Facility borrowings and ~~gas industry, we may, from time to time, have various contractual work commitments and/or letters of credit as described in our notes to~~repayments and the ~~unaudited condensed consolidated financial statements.~~

~~Recent Accounting Pronouncements~~

~~In May 2014, the FASB issued Accounting Standards Update 2014-09,~~ ~~“Revenue from Contracts with Customers (Topic 606)~~” (“ASU 2014-09”). ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. We have completed our review of contracts for each revenue stream identified within our business and are currently finalizing our conclusion on any changes in revenue recognition upon adoptionreceipt of the ~~revised guidance. Based on assessments~~PPP Loan. See Note 8 of the Notes to ~~date,~~Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Off–Balance Sheet Arrangements

As of June 30, 2020, we ~~believe ASU 2014-09 will impact the presentation~~had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of future revenues and expenses by including certain transportation and gathering costs, along with various other fees such as compression and marketing fees net within revenues. The inclusion of these costs within revenues will not impact our revenue recognition, financial position, net income or cash flows. In addition, several industry interpretations are currently open for public comment. We cannot quantitatively assess the impact of ASU 2014-09 on our financial statements until final consensus is reached on these various industry matters. Once all pending industry interpretations are addressed, we will finalize our assessment of ASU 2014-09. We are in the process of evaluating the information technology and internal control changesrecent accounting pronouncements that will ~~be required for adoption based on our contract review process, but we do not currently anticipate material impacts~~affect us, see Note 2 of the Notes to either information technology or internal controls. However, this assessment is pending conclusion of various industry interpretations. We intend to apply the modified retrospective approach upon adoptionUnaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this ~~standard on the effective date of January 1, 2018.~~

~~In February 2016, the FASB issued Accounting Standards Update 2016-02,~~ ~~“Leases (Topic 842)”~~ ~~(“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet~~quarterly report for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are in the initial evaluation and planning stages for ASU 2016-02 and do not expect to move beyond this stage until completion of its evaluation of ASU 2014-09, which is expected to occur in the latter half of 2017.additional information.

~~In July 2017, the FASB issued Accounting Standards Update 2017-11,~~ ~~“Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)”~~ (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We do not believe the adoption of ASU 2017-11 will have a material impact on its financial position, results of operations or cash flows.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

~~ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.~~

WeIn the normal course of our business operations, we are exposed to ~~a variety of market~~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 the Legacy Amplify Form 10-K.

Commodity Price Risk

Our major market risk exposure is in the prices that we receive for our oil, natural gas and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices we receive. It has been our practice to enter into fixed price ~~risk, interest rate risk~~swaps and ~~counterparty~~costless collars only with lenders and ~~customer risk. We address these risks through a program~~their affiliates under our Revolving Credit Facility.

For additional information regarding the volumes of ~~risk management including~~our production covered by commodity derivative contracts and the ~~use~~average prices at which production is hedged as of ~~derivative instruments.~~

~~The primary objective~~June 30, 2020, see Note 6 of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in “Part I. Financial Information — Item 1. Financial Statements — Notes to ~~the~~ Unaudited Condensed Consolidated Financial Statements —included “Item 1. Financial Statements” of this quarterly report.

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. See Note 4.6 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 June 30, 2020.

Counterparty and Customer Credit Risk ~~Management and Derivative Instruments.”~~

~~Commodity Price Exposure~~

We are ~~exposed~~also subject to ~~market~~credit risk ~~as the prices of oil, NGLs and natural gas fluctuate~~ due to ~~changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged and in~~ the ~~long-term, expect to hedge, a significant portion~~concentration of our ~~future production.~~

~~We utilize derivative financial instruments to manage risks related to changes in~~ oil and natural gas ~~prices. As~~receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of ~~September 30, 2017, we utilized fixed price swaps, collars~~nonperformance by counterparties. Some of the lenders, or certain of their affiliates, under our previous and ~~three way collars~~current credit agreements are counterparties to ~~reduce~~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 ~~volatility~~event of ~~oil and natural gas prices on a portion~~default by the counterparty. We have also entered into ISDA Agreements with each of our ~~future expected oil~~counterparties. The terms of the ISDA Agreements provide us and ~~natural gas production.~~

~~For derivative instruments recorded at fair value, the credit standing~~each of our counterparties ~~is analyzed and factored into~~with rights of set-off upon the ~~fair value amounts recognized on~~occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the ~~balance sheet.~~

~~The fair values of our commodity derivatives are largely determined by estimates~~party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. Had all counterparties failed completely to perform according to the terms of the ~~forward curves of the relevant price indices. At September 30, 2017, a 10% change in the forward curves associated with our commodity derivative instruments~~existing contracts, we would have ~~changed our net asset positions by~~had the ~~following amounts:~~

10% Increase

10% Decrease

(in thousands)

Gain (loss):

Gas derivatives

$
(2,408
)
$
2,273

Oil derivatives

$
(5,482
)
$
5,473

~~Interest Rate Risk~~

~~At September 30, 2017, we had indebtedness~~right to offset $39.9 million against amounts outstanding under our ~~Exit~~Revolving Credit Facility at June 30, 2020, reducing our maximum credit exposure to approximately $0.3 million, all of ~~$128.1 million,~~ which ~~bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. Assuming the Exit Facility is fully drawn, a~~was with one ~~percent increase in interest rates for the three months ended September 30, 2017 would have resulted in a $0.4 million increase in interest cost, before capitalization.~~counterparty.

At September 30, 2017, we did not have any interest rate derivatives in place and have not historically utilized interest rate derivatives. In the future, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing or future debt issues. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

ITEM 4.

CONTROLS AND PROCEDURES.

~~Item 4. Controls and Procedures~~

Evaluation of Disclosure Controls and Procedures

~~During~~As required by Rules 13a-15(b) and 15d-15(b) of the ~~period covered by this report,~~Exchange Act, we have evaluated, under the supervision and with the participation of our management, ~~carried out an evaluation of~~including the principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures ~~pursuant to~~(as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange ~~Act Rule 13a-15.~~Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to ~~ensure~~provide reasonable assurance that the information required to be disclosed by us in ~~the~~ reports that we file ~~with~~under the ~~SEC~~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,~~SEC. Based upon the evaluation, the principal executive officer and that such information is accumulated and communicated to our management, including our President and Chief Executive Officer and our Vice President and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosures. Based on that evaluation, our President and Chief Executive Officer and our Vice President and Chief Accounting Officerprincipal financial officer have concluded that ~~as of September 30, 2017, these~~our disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2020.

The full impact of COVID-19 on our business is uncertain. In order to protect the health and ~~ensured that~~safety of our employees, we took proactive steps to allow employees to work remotely and to reduce the ~~information required to be disclosed~~number of employees on site at any one time in our ~~reports filed~~field areas to comply with social distancing guidelines. We believe that our internal controls and procedures are still functioning as designed and were effective for the ~~SEC is recorded, processed, summarized and reported on a timely basis.~~most recent quarter.

~~Changes~~Change in Internal Control ~~over~~Over Financial Reporting

~~There were no~~No changes in our internal control over financial reporting occurred during the most recent quarter ~~ended September 30, 2017,~~ that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

PART ~~II -~~ II—OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS.

~~Item 1. Legal Proceedings~~

~~From time to time, we are party to various~~For information regarding legal proceedings, arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. ~~See “Part I. Financial Information — Item~~see Part I, “Item 1. Financial Statements,” Note 15, “Commitments and Contingencies — Litigation and Environmental” of the Notes to ~~the~~ Unaudited Condensed Consolidated Financial Statements ~~— Note 14. Commitments and Contingencies”,~~included in this quarterly report, which is incorporated ~~in this item~~herein by reference.

~~Item 1A. Risk Factors~~

ITEM 1A.
RISK FACTORS.

Our business faces many risks. Any of the risks discussed elsewhere in this ~~Quarterly Report~~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.

In addition to the ~~other information set forth~~risk factors disclosed in ~~this report, you should carefully consider the factors discussed below and described~~Item 1A. Risk Factors in ~~Part I, Item 1A of~~ our ~~Annual Report on~~2019 Form 10-K, ~~for~~we face risks including the ~~year ended December 31, 2016, filed with the SEC on March 30, 2017.~~

Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of saltwater produced in conjunction with our hydrocarbons, which could limit our ability to produce oil and gas economically and have a material adverse effect on our business.

We dispose of large volumes of saltwater produced in conjunction with the oil and natural gas produced from our drilling and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, the applicable legal requirements may be subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements.

following:

The ~~adoption and implementation of any new laws, regulations, or directives that restrict our ability to dispose of saltwater by plugging back the depths of disposal wells, reducing the volume~~oversupply of oil and natural gas ~~wastewater disposed~~and lower demand caused by the COVID-19 pandemic, the failure of oil producing countries to sufficiently curtail production and general global economic instability may result in ~~such~~transportation and storage constraints, reduced production or the shut-in of our producing wells, ~~restricting disposal well locations, or requiring us to shut down disposal wells, could require the Company to cease operations at a substantial number~~any of ~~its oil and natural gas wells,~~ which would ~~have a material adverse effect on our ability to produce oil and gas economically and, accordingly, could materially and~~ adversely affect our business, financial condition and results of operations.

In March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the United States. The spread of COVID-19 has caused significant volatility in U.S. and international markets. There is significant uncertainty regarding the breadth and duration of business disruptions related to COVID-19, as well as its impact on the U.S. and international economies. The outbreak of COVID-19 in the United States and the uncertainty of its impact, has contributed to an unprecedented oversupply of and decline in demand for oil and natural gas. At this time, the full extent to which COVID-19 will negatively impact the global economy and our business is uncertain.

In addition, in March 2020, oil prices severely declined following unsuccessful negotiations between members of OPEC and certain nonmembers, including Russia, to implement production cuts in an effort to decrease the global oversupply and to rebalance supply and demand due to the ongoing COVID-19 pandemic. In April 2020, members of OPEC and Russia agreed to temporary production reductions, but uncertainty about whether such production cuts and/or the duration of such reductions will be sufficient to rebalance supply and demand remains and may continue for the foreseeable future. We anticipate further market and commodity price volatility for the remainder of 2020 as a result of the events described above.

To the extent that the outbreak of COVID-19 continues to negatively impact demand and OPEC members and other oil exporting nations fail to take actions aimed at supporting and stabilizing commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period. This excess supply could, in turn, result in transportation and storage capacity constraints, as well as shut-ins and production curtailment in the United States. If, in the future, our transportation and/or storage capacity becomes constrained, we may be required to shut-in wells or curtail production, which may adversely affect our business, financial condition and results of operations.

In addition, uncertainties regarding the global economic and financial environment could lead to an extended national or global economic recession. A slowdown in economic activity caused by a recession would likely reduce national and worldwide demand for oil and natural gas and result in lower commodity prices. Costs of exploration, development and production have not yet adjusted to current economic conditions, or in proportion to the significant reduction in product prices.

Over the past several years, capital and credit markets for the oil and natural gas industry have experienced volatility and disruption. Further market volatility and disruption and concerns regarding borrower solvency may substantially diminish the availability of funds from those markets, increase the cost of accessing the credit markets, subject borrowers to stricter lending standards, or may cause lenders to cease providing funding to borrowers, any of which may adversely affect our business, financial condition and results of operations.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

~~Item 2. Unregistered Sales of Equity Securities and Use of Proceeds~~The following table summarizes our repurchase activity during the three months ended June 30, 2020:

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)
April 1, 2020 - April 30, 2020		1,020	$	0.54		—	n/a
May 1, 2020 - May 31, 2020		10,279	$	1.29		—	n/a
June 1, 2020 - June 30, 2020		3,737	$	1.12		—	n/a

~~None.~~

(1)

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

~~Item 3. Defaults Upon Senior Securities~~

ITEM 3.
DEFAULTS UPON SENIOR SECURITIES.

None.

~~Item 4. Mine Safety Disclosures~~

ITEM 4.
MINE SAFETY DISCLOSURES.

Not applicable.

~~Item 5. Other Information~~

~~None.~~

~~Item 6. Exhibits~~

~~Exhibits included in this Quarterly Report are listed in the Exhibit Index and incorporated herein by reference.~~

~~EXHIBIT INDEX~~

~~Exhibit~~
~~Number~~ITEM 5.

OTHER INFORMATION.

None.

ITEM 6.

~~Exhibit Description~~EXHIBITS.

~~2.1~~Exhibit Number	First Amended Joint Chapter 11 Plan Of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate, dated September 28, 2016 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on October 4, 2016, and incorporated herein by reference).
		Description
3.1	—		Second Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Registration Statement on Form 8-A filed on October 21, 2016, and incorporated herein by reference).

3.2	—		Certificate of Amendment to the Second Amended and Restated ~~Bylaws~~Certificate of Incorporation of Midstates Petroleum Company, Inc. ~~(filed as~~, dated August 6, 2019 (incorporated by reference to Exhibit ~~3.2 to~~3.1 of the Company’s ~~Registration Statement~~Current Report on Form ~~8-A~~8-K (File No. 001-35512) filed on ~~October 21, 2016, and incorporated herein by reference)~~August 6, 2019).

~~4.1~~3.3	—		~~Warrant Agreement, dated as~~Second Amended and Restated Bylaws of ~~October 21, 2016 between~~ Midstates Petroleum Company Inc. ~~and American Stock Transfer & Trust Company, LLC (filed as~~(incorporated by reference to Exhibit ~~4.1 to~~3.2 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on ~~October 27, 2016, and incorporated herein by reference)~~August 6, 2019).

~~4.2~~	Warrant Agreement, dated as of October 21, 2016, between Midstates Petroleum Company, Inc. and American Stock Transfer & Trust Company, LLC (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 27, 2016, and incorporated herein by reference).

10.1	—		~~First~~Borrowing Base Redetermination Agreement and Third Amendment to ~~Senior Secured~~ Credit Agreement, dated ~~May 24, 2017,~~June 12, 2020, by and among ~~Midstates Petroleum Company,~~Amplify Energy Operating LLC, Amplify Acquisitionco, Inc., ~~Midstates Petroleum Company LLC, as borrower, SunTrust~~the guarantors party thereto, Bank of Montreal, as administrative agent, and ~~certain~~the other lenders and agents from time to time party thereto ~~(filed as~~(incorporated by reference to Exhibit 10.1 toof the Company’s Current Report on Form 8-K (File No. 001-35512) filed on ~~May 26, 2017, and incorporated herein by reference)~~June 15, 2020).

~~10.2~~	Separation Agreement and General Release of Claims, dated as of June 7, 2017, by and between Midstates Petroleum Company, Inc. and Nelson M. Haight (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 7, 2017, and incorporated herein by reference).

~~10.3~~	Amendment No. 1 to Executive Employment Agreement, dated as of August 22, 2017, by and between Midstates Petroleum Company, Inc. and Frederic F. Brace (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 25, 2017, and incorporated herein by reference).

~~10.4~~	Executive Employment Agreement, effective as of November 1, 2017, by and between Midstates Petroleum Company, Inc. and David J. Sambrooks (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 26, 2017, and incorporated herein by reference).

~~10.5~~	Form of Restricted Stock Unit Award Agreement, effective as of November 1, 2017, by and between Midstates Petroleum Company, Inc. and David J. Sambrooks (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on October 26, 2017, and incorporated herein by reference).

~~10.6~~	Form of Performance Stock Unit Award Agreement, effective as of November 1, 2017, by and between Midstates Petroleum Company, Inc. and David J. Sambrooks (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on October 26, 2017, and incorporated herein by reference).

~~10.7~~	Borrowing Base Redetermination Agreement, dated as of October 27, 2017, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, the lenders party thereto and SunTrust Bank, N.A., as administrative agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 1, 2017, and incorporated herein by reference).

31.1*	—		~~Sarbanes-Oxley Section 302 certification~~Certification of ~~Principal~~Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

31.2*	—		~~Sarbanes-Oxley Section 302 certification~~Certification of ~~Principal~~Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

32.1**	—		~~Sarbanes-Oxley Section 906 certification~~Certifications of ~~Principal~~Chief Executive Officer and ~~Principal~~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.INS*	—	Inline XBRL Instance ~~Document.~~Document

101.SCH*	—	Inline XBRL Schema ~~Document.~~Document

101.CAL*	—	Inline XBRL Calculation Linkbase ~~Document.~~Document

101.DEF*	—	Inline XBRL Definition Linkbase ~~Document.~~Document

101.LAB*Exhibit Number		Description
101.LAB*	—	Inline XBRL Labels Linkbase Document

101.PRE*	~~XBRL Presentation Linkbase Document.~~

*—	~~Filed herewith~~Inline XBRL Presentation Linkbase Document
**	~~Furnished herewith~~
104*	—	Cover Page Interactive Data File (embedded within the Inline XBRL document)

~~SIGNATURES~~

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

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	~~MIDSTATES PETROLEUM COMPANY, INC.~~Amplify Energy Corp.
	(Registrant)

~~Dated: November 14, 2017~~	~~/s/ David J. Sambrooks~~
	~~David J. Sambrooks~~
	~~President and Chief Executive Officer~~
	~~(Principal Executive Officer)~~

~~Dated: November 14, 2017~~Date: August 5, 2020	By:	/s/ ~~Richard W. McCullough~~Martyn Willsher
	~~Richard W. McCullough~~Name:	Martyn Willsher
	Title:	Interim Chief Executive Officer, Senior Vice President and Chief Financial Officer


Date: August 5, 2020	By:	/s/ Denise DuBard
	Name:	Denise DuBard
	Title:	Vice President and Chief Accounting Officer
	~~(Principal Financial Officer and Principal Accounting Officer)~~

	September 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	76,548		$	76,838
Accounts receivable:
Oil and gas sales	29,776			36,988
Joint interest billing	3,193			4,281
Other	630			2,456
Commodity derivative contracts	2,896			—
Other current assets	1,821			3,326
Total current assets	114,864			123,889
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting
Proved properties	709,647			573,150
Unproved properties not being amortized	26,178			65,080
Other property and equipment	6,543			6,339
Less accumulated depreciation, depletion and amortization	(59,349		)	(12,974		)
Net property and equipment	683,019			631,595
OTHER NONCURRENT ASSETS	7,156			5,455
TOTAL	$	805,039		$	760,939

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	9,480		$	2,521
Accrued liabilities	46,987			53,731
Total current liabilities	56,467			56,252
LONG-TERM LIABILITIES:
Asset retirement obligations	14,039			14,200
Commodity derivative contracts	278			—
Long-term debt	128,059			128,059
Other long-term liabilities	599			614
Total long-term liabilities	142,975			142,873

COMMITMENTS AND CONTINGENCIES (Note 14)

STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at September 30, 2017 and December 31, 2016	—			—
Warrants, 6,625,554 warrants outstanding at September 30, 2017 and December 31, 2016	37,329			37,329
Common stock, $0.01 par value, 250,000,000 shares authorized; 25,098,834 shares issued and 25,065,425 shares outstanding at September 30, 2017 and 24,994,867 shares issued and outstanding at December 31, 2016	251			250
Treasury stock	(626		)	—
Additional paid-in-capital	522,823			514,305
Retained earnings	45,820			9,930
Total stockholders’ equity	605,597			561,814
TOTAL	$	805,039		$	760,939

	Successor			Predecessor			Successor			Predecessor
	For the Three Months Ended			For the Three Months Ended			For the Nine Months Ended			For the Nine Months Ended
	September 30, 2017			September 30, 2016			September 30, 2017			September 30, 2016
REVENUES:
Oil sales	$	27,190		$	35,584		$	85,497		$	104,832
Natural gas liquid sales	10,656			8,939			31,580			25,073
Natural gas sales	13,970			17,676			46,321			44,486
Gains (losses) on commodity derivative contracts—net	(3,591		)	—			8,767			—
Other	1,490			1,994			3,244			4,322
Total revenues	49,715			64,193			175,409			178,713
EXPENSES:
Lease operating and workover	15,653			17,650			48,064			49,520
Gathering and transportation	3,699			4,296			11,027			13,428
Severance and other taxes	2,352			1,788			6,168			4,776
Asset retirement accretion	274			452			833			1,316
Depreciation, depletion, and amortization	15,170			15,756			46,471			59,229
Impairment in carrying value of oil and gas properties	—			33,887			—			224,584
General and administrative	7,255			3,308			23,102			19,093
Debt restructuring costs and advisory fees	—			—			—			7,589
Total expenses	44,403			77,137			135,665			379,535
OPERATING INCOME (LOSS)	5,312			(12,944		)	39,744			(200,822		)
OTHER EXPENSE:
Interest income	—			—			—			81
Interest expense—net of amounts capitalized (excludes interest expense of $47.6 million and $79.3 million on senior and secured notes subject to compromise for the three and nine months ended September 30, 2016, respectively)	(1,649		)	(2,668		)	(3,854		)	(65,719		)
Reorganization items, net	—			(22,772		)	—			57,764
Total other expense	(1,649		)	(25,440		)	(3,854		)	(7,874		)
INCOME (LOSS) BEFORE TAXES	3,663			(38,384		)	35,890			(208,696		)
Income tax expense	—			—			—			—
NET INCOME (LOSS)	$	3,663		$	(38,384	)	$	35,890		$	(208,696	)
Successor participating securities—non-vested restricted stock	(82		)	—			(932		)	—
Predecessor participating securities—non-vested restricted stock	—			—			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	3,581		$	(38,384	)	$	34,958		$	(208,696	)
Basic and diluted net income (loss) per share attributable to common shareholders	$	0.14		$	(3.60	)	$	1.39		$	(19.61	)
Basic and diluted weighted average number of common shares outstanding (Note 12)	25,116			10,657			25,074			10,644

	Series A Preferred Stock		Common Stock			Warrants		Treasury Stock			Additional Paid-in-Capital		Retained Earnings			Total Stockholders’ Equity
Balance as of December 31, 2016 (Successor)	$	—	$	250		$	37,329	$	—		$	514,305	$	9,930		$	561,814
Share-based compensation	—		1			—		—			8,518		—			8,519
Acquisition of treasury stock	—		—			—		(626		)	—		—			(626		)
Net income	—		—			—		—			—		35,890			35,890
Balance as of September 30, 2017 (Successor)	$	—	$	251		$	37,329	$	(626	)	$	522,823	$	45,820		$	605,597

	Series A Preferred Stock		Common Stock			Warrants		Treasury Stock			Additional Paid-in-Capital		Retained Deficit			Total Stockholders’ Deficit
Balance as of December 31, 2015 (Predecessor)	$	—	$	110		$	—	$	(3,081	)	$	888,247	$	(2,211,342	)	$	(1,326,066	)
Share-based compensation	—		(1		)	—		—			1,726		—			1,725
Acquisition of treasury stock	—		—			—		(53		)	—		—			(53		)
Net loss	—		—			—		—			—		(208,696		)	(208,696		)
Balance as of September 30, 2016 (Predecessor)	$	—	$	109		$	—	$	(3,134	)	$	889,973	$	(2,420,038	)	$	(1,533,090	)

	Successor			Predecessor
	For the Nine Months Ended			For the Nine Months Ended
	September 30, 2017			September 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	35,890		$	(208,696	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gains on commodity derivative contracts—net	(8,767		)	—
Net cash received for commodity derivative contracts not designated as hedging instruments	6,149			—
Asset retirement accretion	833			1,316
Depreciation, depletion, and amortization	46,471			59,229
Impairment in carrying value of oil and gas properties	—			224,584
Share-based compensation, net of amounts capitalized to oil and gas properties	7,102			1,275
Amortization of deferred financing costs	277			4,495
Paid-in-kind interest expense	—			3,531
Amortization of deferred gain on debt restructuring	—			(8,246		)
Operating lease abandonment	—			1,574
Noncash reorganization items	—			(70,489		)
Change in operating assets and liabilities:
Accounts receivable—oil and gas sales	4,929			(311		)
Accounts receivable—JIB and other	2,641			21,411
Other current and noncurrent assets	(98		)	(5,572		)
Accounts payable	1,392			870
Accrued liabilities	(7,381		)	54,520
Other	(121		)	(1,247		)
Net cash provided by operating activities	$	89,317		$	78,244
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	$	(92,841	)	$	(129,072	)
Proceeds from the sale of oil and gas equipment and properties	4,235			—
Net cash used in investing activities	$	(88,606	)	$	(129,072	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	—			249,384
Deferred financing costs	(375		)	—
Acquisition of treasury stock	(626		)	(53		)
Net cash (used in) provided by financing activities	$	(1,001	)	$	249,331
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	$	(290	)	$	198,503
Cash and cash equivalents, beginning of period	$	76,838		$	81,093
Cash and cash equivalents, end of period	$	76,548		$	279,596

SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued — not paid	$	19,865		$	12,238
Cash paid for interest, net of capitalized interest of $2.1 million for the nine months ended September 30, 2017 (no capitalized interest for the nine months ended September 30, 2016)	$	3,708		$	5,821
Cash paid for reorganization items	$	—		$	12,725

	For the Three Months Ended June 30, 2019		For the Six Months Ended June 30, 2019
(Unaudited) (In thousands, except per unit amounts)
Revenues	$	82,772	$	177,768
Net income (loss)		23,385		(7,742	)
Earnings per share:
Basic	$	0.57	$	(0.18	)
Diluted	$	0.57	$	(0.18	)

	Fair Value Measurements at September 30, 2017
			Significant Other			Significant
	Quoted Prices in Active Markets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
	(in thousands)
Derivative Assets:
Commodity derivative oil swaps	$	—	$	722		$	—	$	722
Commodity derivative gas swaps	$	—	$	1,006		$	—	$	1,006
Commodity derivative oil collars	$	—	$	2,356		$	—	$	2,356
Commodity derivative gas collars	$	—	$	2,806		$	—	$	2,806
Total assets	$	—	$	6,890		$	—	$	6,890

Derivative Liabilities:
Commodity derivative oil swaps	$	—	$	(772	)	$	—	$	(772	)
Commodity derivative gas swaps	$	—	$	—		$	—	$	—
Commodity derivative oil collars	$	—	$	(1,380	)	$	—	$	(1,380	)
Commodity derivative gas collars	$	—	$	(2,120	)	$	—	$	(2,120	)
Total liabilities	$	—	$	(4,272	)	$	—	$	(4,272	)

	Fair Value Measurements at June 30, 2020 Using
	Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	49,302	$	—	$	49,302
Interest rate derivatives		—		—		—		—
Total assets	$	—	$	49,302	$	—	$	49,302

Liabilities:
Commodity derivatives	$	—	$	6,877	$	—	$	6,877
Interest rate derivatives		—		3,693		—		3,693
Total liabilities	$	—	$	10,570	$	—	$	10,570

	NYMEX WTI
	Fixed Swaps			Collars					Three Way Collars
	Hedge Position (Bbls)	Weighted Avg Strike Price		Hedge Position (Bbls)	Weighted Avg Ceiling Price		Weighted Avg Floor Price		Hedge Position (Bbls)	Weighted Avg Ceiling Price		Weighted Avg Floor Price		Weighted Avg Sub-Floor Price
Quarter Ended:
September 30, 2017(2)	207,000	$	55.29	46,000	$	60.00	$	50.00	115,000	$	62.80	$	50.00	$	40.00
December 31, 2017(1)(2)	276,000	$	53.58	46,000	$	60.00	$	50.00	115,000	$	62.80	$	50.00	$	40.00
March 31, 2018(1)	99,000	$	50.61	—	$	—	$	—	225,000	$	62.14	$	50.00	$	40.00
June 30, 2018(1)	145,600	$	51.22	—	$	—	$	—	182,000	$	60.65	$	50.00	$	40.00
September 30, 2018(1)	92,000	$	50.38	—	$	—	$	—	184,000	$	59.93	$	50.00	$	40.00
December 31, 2018(1)	92,000	$	50.38	—	$	—	$	—	46,000	$	56.70	$	50.00	$	40.00

	NYMEX HENRY HUB
	Fixed Swaps			Collars					Three Way Collars
	Hedge Position (MMBtu)	Weighted Avg Strike Price		Hedge Position (MMBtu)	Weighted Avg Ceiling Price		Weighted Avg Floor Price		Hedge Position (MMBtu)	Weighted Avg Ceiling Price		Weighted Avg Floor Price		Weighted Avg Sub-Floor Price
Quarter Ended:
September 30, 2017	2,944,000	$	3.38	368,000	$	3.63	$	3.15	—	$	—	$	—	$	—
December 31, 2017(1)	1,907,000	$	3.43	551,000	$	3.84	$	3.23	610,000	$	4.30	$	3.25	$	2.50
March 31, 2018(1)(3)	1,350,000	$	3.47	—	$	—	$	—	1,530,000	$	4.38	$	3.25	$	2.50
June 30, 2018(1)	—	$	—	—	$	—	$	—	1,365,000	$	3.40	$	3.00	$	2.50
September 30, 2018(1)	—	$	—	—	$	—	$	—	1,380,000	$	3.40	$	3.00	$	2.50
December 31, 2018(1)	—	$	—	—	$	—	$	—	1,380,000	$	3.40	$	3.00	$	2.50
March 31, 2019(1)	—	$	—	—	$	—	$	—	1,350,000	$	3.40	$	3.00	$	2.50

	Remaining
	2020			2021			2022
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (MMBtu)		1,450,000			925,000			500,000
Weighted-average fixed price	$	2.26		$	2.49		$	2.45

Collar contracts:
Two-way collars
Average monthly volume (MMBtu)		420,000			925,000			200,000
Weighted-average floor price	$	2.60		$	2.10		$	2.10
Weighted-average ceiling price	$	2.88		$	3.28		$	2.99

Natural Gas Basis Swaps:
PEPL basis swaps:
Average monthly volume (MMBtu)		600,000			500,000			—
Weighted-average spread	$	(0.46	)	$	(0.40	)	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		199,300			33,750			30,000
Weighted-average fixed price	$	57.41		$	56.57		$	55.32

Collar contracts:
Two-way collars
Average monthly volume (Bbls)		14,300			—			—
Weighted-average floor price	$	55.00		$	—		$	—
Weighted-average ceiling price	$	62.10		$	—		$	—

Three-way collars
Average monthly volume (Bbls)		30,500			—			—
Weighted-average ceiling price	$	65.75		$	—		$	—
Weighted-average floor price	$	50.00		$	—		$	—
Weighted-average sub-floor price	$	40.00		$	—		$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		111,450			22,800			—
Weighted-average fixed price	$	21.99		$	24.25		$	—

Type	Balance Sheet Location (1)	September 30, 2017
Oil swaps	Derivative financial instruments — current assets	$	49
Gas swaps	Derivative financial instruments — current assets	1,006
Oil collars	Derivative financial instruments — current assets	969
Gas collars	Derivative financial instruments — current assets	872
Oil swaps	Derivative financial instruments — noncurrent liabilities	(98		)
Oil collars	Derivative financial instruments — noncurrent liabilities	6
Gas collars	Derivative financial instruments — noncurrent liabilities	(186		)
Total derivative fair value at period end		$	2,618

		September 30, 2017
Not Designated as		Gross Recognized			Gross Amounts			Net Recognized Fair Value
ASC 815 Hedges	Balance Sheet Location Classification	Assets/Liabilities			Offset			Assets/Liabilities
Derivative Assets:
Commodity contracts	Derivative financial instruments — current	$	5,858		$	(2,962	)	$	2,896
Commodity contracts	Derivative financial instruments — noncurrent	1,032			(1,032		)	—
		$	6,890		$	(3,994	)	$	2,896
Derivative Liabilities:
Commodity contracts	Derivative financial instruments — current	$	(2,962	)	$	2,962		$	—
Commodity contracts	Derivative financial instruments — noncurrent	(1,310		)	1,032			(278		)
		$	(4,272	)	$	3,994		$	(278	)

	For the Three Months Ended			For the Nine Months Ended
	September 30, 2017			September 30, 2017
Net cash received for commodity derivative contracts	$	2,909		$	6,149
Unrealized net (losses) gains	(6,500		)	2,618
Gains (losses) on commodity derivative contracts—net	$	(3,591	)	$	8,767

	Successor			Predecessor
	Nine Months Ended			Nine Months Ended
	September 30, 2017			September 30, 2016
Asset retirement obligations — beginning of period	$	14,200		$	18,708
Liabilities incurred	259			520
Revisions	—			—
Liabilities settled	(107		)	(278		)
Liabilities eliminated through asset sales	(1,146		)	—
Current period accretion expense	833			1,316
Asset retirement obligations — end of period	$	14,039		$	20,266

	Common Stock	Treasury Stock(1)
Share count as of December 31, 2016	24,994,867	—
Common stock issued	103,967	—
Acquisition of treasury stock	—	(33,409	)
Share count as of September 30, 2017	25,098,834	(33,409	)

	Restricted Stock		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2016	685,662		$	19.66
Granted	17,500		$	18.62
Vested	(103,967	)	$	19.66
Forfeited	(104,401	)	$	19.66
Non-vested shares outstanding at September 30, 2017	494,794		$	19.63

	Options		Range of Exercise Prices		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)
Stock options outstanding at December 31, 2016	627,806				$	19.66	9.1
Granted	4,000		$	19.08	$	19.08	9.5
Vested	(103,967	)	$	19.08-20.97	$	19.66	—
Forfeited	(104,401	)	$	19.66	$	19.66	—
Stock options outstanding at September 30, 2017	423,438				$	19.66	9.1
Vested and exercisable at end of period(1)	103,967		$	19.08-20.97	$	19.66	9.1

	Three Months Ended			Nine Months Ended
	September 30, 2017			September 30, 2017
	(in thousands, except per share amounts)			(in thousands, except per share amounts)
Net Earnings:
Net income	$	3,663		$	35,890
Participating securities—non-vested restricted stock	(82		)	(932		)
Basic and diluted earnings	$	3,581		$	34,958

Common Shares:
Common shares outstanding — basic (1)	25,116			25,074
Dilutive effect of potential common shares	—			—
Common shares outstanding — diluted	25,116			25,074

Net Earnings Per Share:
Basic	$	0.14		$	1.39
Diluted	$	0.14		$	1.39
Antidilutive stock options (2)	424			526
Antidilutive warrants (3)	6,626			6,626

	Three Months Ended September 30, 2017	Three Months Ended June 30, 2017	Increase/(Decrease) in Production

Average daily production:
Oil (Bbls)	4,940	4,938	—	%
Natural gas liquids (Bbls)	4,145	4,466	(7.2	)%
Natural gas (Mcf)	51,130	53,246	(4.0	)%
Net Boe/day	17,606	18,278	(3.7	)%

		Total Number of Gross Horizontal Wells Spud (1)		Total Number of Gross Horizontal Wells Brought into Production
Mississippian Lime		10		9

	Three Months Ended September 30, 2017	Three Months Ended June 30, 2017	Decrease in Production

Average daily production:
Oil (Bbls)	1,329	1,475	(9.9	)%
Natural gas liquids (Bbls)	992	1,115	(11.0	)%
Natural gas (Mcf)	8,581	9,735	(11.9	)%
Net Boe/day	3,752	4,212	(10.9	)%

	For the Three Months Ended September 30, 2017		For the Nine Months Ended September 30, 2017
Drilling and completion activities	$	36,269	$	89,975
Acquisition of acreage and seismic data	3,845		7,748
Operational capital expenditures incurred	$	40,114	$	97,723
Capitalized G&A, office, ARO & other	1,856		5,512
Capitalized interest	408		2,054
Total capital expenditures incurred	$	42,378	$	105,289

	Three Months Ended September 30,
	Crude Oil			Natural Gas			NGLs			Total
2016 Revenues (Predecessor)	$	35,584		$	17,676		$	8,939		$	62,199
Changes due to volumes	(11,820		)	(3,776		)	(2,649		)	(18,245		)
Changes due to price	3,426			70			4,366			7,862
2017 Revenues (Successor)	$	27,190		$	13,970		$	10,656		$	51,816

	Nine Months Ended September 30,
	Crude Oil			Natural Gas			NGLs			Total
2016 Revenues (Predecessor)	$	104,832		$	44,486		$	25,073		$	174,391
Changes due to volumes	(48,583		)	(12,776		)	(6,717		)	(68,076		)
Changes due to price	29,248			14,611			13,224			57,083
2017 Revenues (Successor)	$	85,497		$	46,321		$	31,580		$	163,398

	For the Three Months Ended September 30, 2017			For the Nine Months Ended September 30, 2017
Cash settlements:
Oil derivatives	$	1,713		$	4,041
Natural gas derivatives	1,196			2,108
Total cash settlements	$	2,909		$	6,149

Gains (losses) due to fair value changes:
Oil derivatives	$	(5,618	)	$	925
Natural gas derivatives	(882		)	1,693
Total gains (losses) on fair value changes	$	(6,500	)	$	2,618

Gains (losses) on commodity derivative contracts—net	$	(3,591	)	$	8,767

	Successor			Predecessor
	For the Nine Months Ended September 30, 2017			For the Nine Months Ended September 30, 2016
Net cash provided by operating activities	$	89,317		$	78,244
Net cash used in investing activities	(88,606		)	(129,072		)
Net cash (used in) provided by financing activities	(1,001		)	249,331
Net change in cash	$	(290	)	$	198,503

	10% Increase			10% Decrease
	(in thousands)
Gain (loss):
Gas derivatives	$	(2,408	)	$	2,273
Oil derivatives	$	(5,482	)	$	5,473