UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2021

OR

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

For the transition period from                      to                     .

Commission File Number: 001-35512

Amplify Energy Corp.

(Exact name of registrant as specified in its charter)

Delaware	82-1326219
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
500 Dallas Street, Suite 1700, Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes  þ    No  ☐

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

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

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

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

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.    þ  Yes      ☐     No

Securities Registered Pursuant to Section 12(b):

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	AMPY	NYSE

As of November 5, 2021, the registrant had 38,023,229 outstanding shares of common stock, $0.01 par value outstanding.

AMPLIFY ENERGY CORP.

TABLE OF CONTENTS

		Page
	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	8
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020	8
	Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2021 and 2020	9
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2021 and 2020	10
	Unaudited Condensed Consolidated Statements of Equity (Deficit) for the Three and Nine Months Ended September 30, 2021 and 2020	11
	Notes to Unaudited Condensed Consolidated Financial Statements	12
	Note 1 – Organization and Basis of Presentation	12
	Note 2 – Summary of Significant Accounting Policies	13
	Note 3 – Revenue	14
	Note 4 – Fair Value Measurements of Financial Instruments	15
	Note 5 – Risk Management and Derivative Instruments	17
	Note 6 – Asset Retirement Obligations	20
	Note 7 – Long-term Debt	20
	Note 8 – Equity (Deficit)	21
	Note 9 – Earnings per Share	22
	Note 10 – Long-Term Incentive Plans	22
	Note 11 – Leases	26
	Note 12 – Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Consolidated Statements of Cash Flows	28
	Note 13 – Related Party Transactions	28
	Note 14 – Commitments and Contingencies	28
	Note 15 – Income Taxes	29
	Note 16 – Subsequent Events	30
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	44
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3.	Defaults Upon Senior Securities	49
Item 4.	Mine Safety Disclosures	49
Item 5.	Other Information	49
Item 6.	Exhibits	50
Signatures		51

i

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

Bbl/d: One Bbl per day.

Bcfe: One billion cubic feet of natural gas equivalent.

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

BOEM: U.S. Bureau of Ocean Energy Management.

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

CO₂: Carbon dioxide.

Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

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

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

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

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand barrels of oil equivalent.

1

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.

Mcf/d: One Mcf per day.

MMBtu: One million Btu.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

MMcfe/d: One MMcfe per day.

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

NGLs: The combination of ethane, propane, butane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

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

2

Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

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

SEC: The U.S. Securities and Exchange Commission

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.

3

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. 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; and

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

4

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 (the “Exchange Act”), 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;

● response to the oil incident that occurred off the coast of Southern California resulting from our pipeline operations at the Beta Field (the “Incident”);

● acquisition and disposition strategy;

● cash flows and liquidity;

● financial strategy;

● ability to replace the reserves we produce through drilling;

● drilling locations;

● oil and natural gas reserves;

● technology;

● realized oil, natural gas and NGL prices;

● production volumes;

● lease operating expense;

● gathering, processing and transportation;

● general and administrative expense;

● future operating results;

● ability to procure drilling and production equipment;

● ability to procure oil field labor;

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

● ability to access capital markets;

● marketing of oil, natural gas and NGLs;

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

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

5

● 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 negative of such terms or other comparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the following risks and uncertainties:

● risks related to the Incident and our response to the Incident;

● 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;

6

● 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;

● our results of evaluation and implementation of strategic alternatives;

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

● the impact of climate change and natural disasters, such as earthquakes, tidal waves, mudslides, fires and floods;

● the impact of local, state and federal governmental regulations;

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

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

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

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

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, 2020 filed with the Securities and Exchange Commission (the “SEC”) on March 11, 2021 (“2020 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 result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

7

PART I—FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS.

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

	September 30,		December 31,
	2021		2020
ASSETS
Current assets:
Cash	$	17,344	$	10,364
Accounts receivable, net		44,748		30,901
Prepaid expenses and other current assets		10,740		15,572
Total current assets		72,832		56,837
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		796,210		775,167
Support equipment and facilities		144,925		142,208
Other		9,617		9,102
Accumulated depreciation, depletion and amortization		(627,881)		(609,231)
Property and equipment, net		322,871		317,246
Long-term derivative instruments		—		873
Restricted investments		4,623		4,623
Operating lease - long term right-of-use asset		3,379		2,500
Other long-term assets		2,212		2,680
Total assets	$	405,917	$	384,759
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	9,166	$	798
Revenues payable		21,095		22,563
Accrued liabilities (see Note 12)		28,238		22,677
Short-term derivative instruments		83,599		10,824
Total current liabilities		142,098		56,862
Long-term debt (see Note 7)		230,000		260,516
Asset retirement obligations		101,077		96,725
Long-term derivative instruments		20,831		847
Operating lease liability		2,132		266
Other long-term liabilities		9,930		3,280
Total liabilities		506,068		418,496
Commitments and contingencies (see Note 14)
Stockholders' equity (deficit):
Preferred stock, $0.01 par value: 50,000,000 shares authorized; no shares issued and outstanding at September 30, 2021 and December 31, 2020		—		—
Warrants, 2,173,913 warrants issued and outstanding at September 30, 2021 and December 31, 2020		4,788		4,788
Common stock, $0.01 par value: 250,000,000 shares authorized; 37,996,974 and 37,663,509 shares issued and outstanding at September 30, 2021 and December 31, 2020, respectively		380		378
Additional paid-in capital		425,508		424,104
Accumulated deficit		(530,827)		(463,007)
Total stockholders' deficit		(100,151)		(33,737)
Total liabilities and equity	$	405,917	$	384,759

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

8

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
Revenues:
Oil and natural gas sales	$	96,841	$	52,488	$	249,510	$	145,163
Other revenues		160		257		353		889
Total revenues		97,001		52,745		249,863		146,052
Costs and expenses:
Lease operating expense		34,486		27,639		92,045		91,190
Gathering, processing and transportation		5,047		5,256		14,676		14,998
Taxes other than income		6,024		3,761		15,708		9,942
Depreciation, depletion and amortization		7,000		7,950		21,736		31,129
Impairment expense		—		—		—		455,031
General and administrative expense		6,448		6,443		19,399		21,551
Accretion of asset retirement obligations		1,665		1,565		4,918		4,617
Loss (gain) on commodity derivative instruments		46,653		14,352		145,139		(74,196)
Other, net		9		118		105		137
Total costs and expenses		107,332		67,084		313,726		554,399
Operating loss		(10,331)		(14,339)		(63,863)		(408,347)
Other (expense) income:
Interest expense, net		(3,078)		(3,362)		(9,327)		(17,218)
Other expense		(61)		196		(141)		(38)
Gain on extinguishment of debt		—		—		5,516		—
Total other expense		(3,139)		(3,166)		(3,952)		(17,256)
Loss before reorganization items, net and income taxes		(13,470)		(17,505)		(67,815)		(425,603)
Reorganization items, net		—		(180)		(6)		(532)
Income tax expense		—		—		—		(85)
Net loss	$	(13,470)	$	(17,685)	$	(67,821)	$	(426,220)
Loss per share: (See Note 9)
Basic and diluted earnings (loss) per share	$	(0.35)	$	(0.47)	$	(1.79)	$	(11.34)
Weighted average common shares outstanding:
Basic and diluted		37,996		37,626		37,937		37,596

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

9

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	For the Nine Months Ended
	September 30,
	2021		2020
Cash flows from operating activities:
Net loss	$	(67,821)	$	(426,220)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		21,736		31,129
Impairment expense		—		455,031
Loss (gain) on derivative instruments		145,142		(70,162)
Cash settlements (paid) received on expired derivative instruments		(51,512)		53,076
Cash settlements received on terminated derivative instruments		—		17,977
Bad debt expense		108		470
Amortization and write-off of deferred financing costs		493		3,134
Gain on extinguishment of debt		(5,516)		—
Accretion of asset retirement obligations		4,918		4,617
Share-based compensation (see Note 10)		1,436		(161)
Settlement of asset retirement obligations		(162)		(199)
Changes in operating assets and liabilities:
Accounts receivable		(13,965)		5,769
Prepaid expenses and other assets		4,832		1,080
Payables and accrued liabilities		16,127		(11,467)
Other		(529)		(476)
Net cash provided by operating activities		55,287		63,598
Cash flows from investing activities:
Additions to oil and gas properties		(23,142)		(31,234)
Additions to other property and equipment		(515)		(828)
Other		404		—
Net cash used in investing activities		(23,253)		(32,062)
Cash flows from financing activities:
Advances on revolving credit facility		—		25,000
Payments on revolving credit facility		(25,000)		(45,000)
Proceeds from the paycheck protection program		—		5,516
Deferred financing costs		(25)		(65)
Dividends to stockholders		—		(3,786)
Shares withheld for taxes		(29)		(40)
Other		—		35
Net cash used in financing activities		(25,054)		(18,340)
Net change in cash, cash equivalents and restricted cash		6,980		13,196
Cash, cash equivalents and restricted cash, beginning of period		10,364		325
Cash, cash equivalents and restricted cash, end of period	$	17,344	$	13,521

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

10

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (DEFICIT)

(In thousands)

	Stockholders' Equity (Deficit)
					Additional
	Common				Paid-in		Accumulated
	Stock		Warrants		Capital		Deficit		Total
Balance at December 31, 2020	$	378	$	4,788	$	424,104	$	(463,007)	$	(33,737)
Net loss		—		—		—		(19,328)		(19,328)
Share-based compensation expense		—		—		(204)		—		(204)
Shares withheld for taxes		—		—		(5)		—		(5)
Other		3		—		(3)		—		—
Balance at March 31, 2021		381		4,788		423,892		(482,335)		(53,274)
Net loss		—		—		—		(35,023)		(35,023)
Share-based compensation expense		—		—		934		—		934
Shares withheld for taxes		—		—		(12)		—		(12)
Balance at June 30, 2021		381		4,788		424,814		(517,358)		(87,375)
Net loss		—		—		—		(13,470)		(13,470)
Share-based compensation expense		—		—		707		—		707
Shares withheld for taxes		—		—		(13)		—		(13)
Balance at September 30, 2021	$	381	$	4,788	$	425,508	$	(530,828)	$	(100,151)

	Stockholders' Equity (Deficit)
					Additional		Accumulated
	Common				Paid-in		Earnings
	Stock		Warrants		Capital		(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)
Shares withheld for taxes		—		—		(14)		—		(14)
Dividends		—		—		—		(3,786)		(3,786)
Balance at March 31, 2020		209		4,790		423,273		(366,176)		62,096
Net loss		—		—		—		(41,336)		(41,336)
Share-based compensation expense		—		—		480		—		480
Expiration of warrants		—		(2)		2		—		—
Shares withheld for taxes		—		—		(20)		—		(20)
Other		—		—		35		—		35
Balance at June 30, 2020		209		4,788		423,770		(407,512)		21,255
Net loss		—		—		—		(17,685)		(17,685)
Share-based compensation expense		—		—		471		—		471
Shares withheld for taxes		—		—		(5)		—		(5)
Balance at September 30, 2020	$	209	$	4,788	$	424,236	$	(425,197)	$	4,036

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

11

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

General

Amplify Energy Corp. (“Amplify Energy,” or the “Company”), is a publicly traded Delaware corporation, in which our common stock is listed on the NYSE under the symbol “AMPY.”

We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Oklahoma, the Rockies, federal waters offshore Southern California, East Texas / North Louisiana and the Eagle Ford. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.

Basis of Presentation

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

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

Use of Estimates

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

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

12

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Market Conditions and COVID-19

In March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic. The nature of COVID-19 led to worldwide shutdowns, reductions in commercial and interpersonal activity and changes in consumer behavior. In attempting to control the spread of COVID-19, governments around the world imposed laws and regulations such as shelter-in-place orders, quarantines, executive orders and similar restrictions. As a result, the global economy had been marked by significant slowdown and uncertainty, which in turn led to a precipitous decline in commodity prices in response to decreased demand, further exacerbated by global energy storage shortages and by the price war among members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”) beginning in the first quarter of 2020. As of the first quarter of 2021, commodity prices have recovered to pre-pandemic levels, due in part to the accessibility of vaccines, reopening of economies after the lockdown, and optimism about the economic recovery. The continued spread of COVID-19, including vaccine resistant strains, or repeated deterioration in oil and natural gas prices could result in additional adverse impacts on the Company’s results of operations, cash flows and financial position, including further asset impairments.

COVID-19 Relief Funding

Paycheck Protection Program. On June 22, 2021, KeyBank National Association (“KeyBank”) notified the Company that the loan under the Paycheck Protection Program (the “PPP Loan”) had been approved for full and complete forgiveness by the Small Business Association. For the nine months ended September 30, 2021, the Company reported a gain on extinguishment of debt for $5.5 million for the PPP Loan forgiveness in the Unaudited Condensed Consolidated Statements of Operations. See Note 7 for additional information.

Employee Retention Credit. The Consolidated Appropriations Act extended and expanded the availability of the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) employee retention credit through September 30, 2021. Subsequently, the American Rescue Plan Act of 2021 (the “ARP Act”), enacted on March 11, 2021, extended and expanded the availability of the employee retention credit through December 31, 2021, however, certain provisions applied only after December 31, 2020. This new legislation expanded the group of qualifying businesses to include businesses with fewer than 500 employees and those who previously qualified for the PPP Loan. The employee retention credit is calculated to be equal to 70% of qualified wages paid to employees after December 31, 2020, and before January 1, 2022. During calendar year 2021, a maximum of $10,000 in qualified wages for each employee per qualifying calendar quarter may be counted in determining the 70% credit. Therefore, the maximum tax credit that can be claimed by an eligible employer is $7,000 per employee per qualifying calendar quarter of 2021. The Company has determined that the qualifications for the credit were met in the first and second quarters of 2021. The Company recognized a $2.8 million employee retention credit during the nine months ended September 30, 2021, which included an approximate $0.8 million credit to general and administrative expense and an approximate $2.0 million credit to lease operating expense in the Unaudited Condensed Consolidated Statements of Operations.

Note 2. Summary of Significant Accounting Policies

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 2020 Form 10-K.

New Accounting Pronouncements

Reference Rate Reform. In March 2020, the Financial Accounting Standard Board (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 became effective on March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. The Company notes no material impact with applying this guidance.

13

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes – Simplifying the Accounting for Income Taxes. In December 2019, the FASB issued an accounting standard update which simplified the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. This accounting standards update removed the following exceptions: (i) exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items; (ii) exception to the 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 (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 amendments in the accounting standards update also improve consistency and simplify other areas of Topic 740 by clarifying and amending existing guidance. The guidance became effective for interim and annual periods beginning after December 15, 2020, with early adoption permitted. The Company adopted the guidance effective January 1, 2021, with all of the anticipated and applicable effects to be required on a prospective basis. The adoption of this guidance did not have a material impact on our consolidated financial statements.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Note 3. Revenue

Revenue from Contracts with Customers

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

Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at September 30, 2021.

Disaggregation of Revenue

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

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
	(in thousands)
Revenues
Oil	$	63,172	$	36,868	$	169,377	$	101,682
NGLs		11,839		5,537		28,386		14,002
Natural gas		21,830		10,083		51,747		29,479
Oil and natural gas sales	$	96,841	$	52,488	$	249,510	$	145,163

14

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 $40.4 million at September 30, 2021 and $25.6 million at December 31, 2020.

Note 4. 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 September 30, 2021 and December 31, 2020. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair market values of the derivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020 were based on estimated forward commodity prices. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables present the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2021 and December 31, 2020 for each of the fair value hierarchy levels:

	Fair Value Measurements at September 30, 2021 Using
					Significant
	Quoted Prices in		Significant Other		Unobservable
	Active Market		Observable Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	5,913	$	—	$	5,913
Interest rate derivatives		—		—		—		—
Total assets	$	—	$	5,913	$	—	$	5,913
Liabilities:
Commodity derivatives	$	—	$	109,013	$	—	$	109,013
Interest rate derivatives		—		1,330		—		1,330
Total liabilities	$	—	$	110,343	$	—	$	110,343

15

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Fair Value Measurements at December 31, 2020 Using
					Significant
	Quoted Prices in		Significant Other		Unobservable
	Active Market		Observable Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	15,449	$	—	$	15,449
Interest rate derivatives		—		—		—		—
Total assets	$	—	$	15,449	$	—	$	15,449
Liabilities:
Commodity derivatives	$	—	$	23,495	$	—	$	23,495
Interest rate derivatives		—		2,752		—		2,752
Total liabilities	$	—	$	26,247	$	—	$	26,247

See Note 5 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 6 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 is 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).

● No impairment expense recorded on proved oil and natural gas properties during the three and nine months ended September 30, 2021.

● For the nine months ended September 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 in 2020.

● Unproved oil and natural gas properties are reviewed for impairment based on time or geological factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered.

16

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

● No impairment expense recorded on unproved oil and natural gas properties during the three and nine months ended September 30, 2021.

● We recognized $49.3 million of impairment expense on unproved properties for the nine months ended September 30, 2020, which was related to expiring leases and the evaluation of qualitative and quantitative factors related to the decline in commodity prices in 2020.

Note 5. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices, but also limit the benefits that would be realized if prices increase.

Certain inherent business risks are associated with commodity derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our current credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. See Note 7 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 instruments at fair value.

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub. We also enter into oil derivative contracts indexed to NYMEX-WTI. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

In April 2020, the Company monetized a portion of its 2021 crude oil hedges for total cash proceeds of approximately $18.0 million.

17

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At September 30, 2021, we had the following open commodity positions:

	Remaining
	2021		2022		2023
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (MMBtu)		970,000		695,000		—
Weighted-average fixed price	$	2.49	$	2.56	$	—
Collar contracts:
Two-way collars
Average monthly volume (MMBtu)		830,000		775,000		270,000
Weighted-average floor price	$	2.06	$	2.56	$	2.50
Weighted-average ceiling price	$	3.28	$	3.44	$	3.28
Natural Gas Basis Swaps:
PEPL basis swaps:
Average monthly volume (MMBtu)		500,000		—		—
Weighted-average spread	$	(0.40)	$	—	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		172,500		99,000		55,000
Weighted-average fixed price	$	49.37	$	55.68	$	57.30
Collar contracts:
Two-way collars
Average monthly volume (Bbls)		—		22,500		—
Weighted-average floor price	$	—	$	58.33	$	—
Weighted-average ceiling price	$	—	$	67.42	$	—
Three-way collars
Average monthly volume (Bbls)		72,500		89,000		30,000
Weighted-average ceiling price	$	50.36	$	55.55	$	67.15
Weighted-average floor price	$	40.00	$	42.92	$	55.00
Weighted-average sub-floor price	$	30.00	$	32.58	$	40.00
NGL Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		20,300		—		—
Weighted-average fixed price	$	23.74	$	—	$	—

18

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2021, we had the following interest rate swap open positions:

	Remaining
	2021			2022
Average Monthly Notional (in thousands)	$	125,000		$	75,000
Weighted-average fixed rate		1.612	%		1.281	%
Floating rate		1 Month LIBOR			1 Month LIBOR

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2021 and December 31, 2020. 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.

				Liability				Liability
		Asset Derivatives		Derivatives		Asset Derivatives		Derivatives
		September 30,		September 30,		December 31,		December 31,
Type	Balance Sheet Location	2021		2021		2020		2020
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	1,952	$	84,412	$	6,088	$	15,007
Interest rate swaps	Short-term derivative instruments		—		1,139		—		1,905
Gross fair value			1,952		85,551		6,088		16,912
Netting arrangements			(1,952)		(1,952)		(6,088)		(6,088)
Net recorded fair value	Short-term derivative instruments	$	—	$	83,599	$	—	$	10,824
Commodity contracts	Long-term derivative instruments	$	3,961	$	24,601	$	9,361	$	8,488
Interest rate swaps	Long-term derivative instruments		—		191		—		847
Gross fair value			3,961		24,792		9,361		9,335
Netting arrangements			(3,961)		(3,961)		(8,488)		(8,488)
Net recorded fair value	Long-term derivative instruments	$	—	$	20,831	$	873	$	847

Loss (Gain) on Derivative Instruments

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 Consolidated Statements of 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 Nine Months Ended
	Statements of	September 30,				September 30,
	Operations Location	2021		2020		2021		2020
Commodity derivative contracts	Loss (gain) on commodity derivatives	$	46,653	$	14,352	$	145,139	$	(74,196)
Loss (gain) on interest rate derivatives	Interest expense, net		47		(20)		3		4,034

19

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6. 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 nine months ended September 30, 2021 (in thousands):

Asset retirement obligations at beginning of period	$	97,149
Liabilities added from acquisition or drilling		29
Liabilities settled		(162)
Liabilities removed upon sale of wells		(113)
Accretion expense		4,918
Revision of estimates		3
Asset retirement obligation at end of period		101,824
Less: Current portion		(747)
Asset retirement obligations - long-term portion	$	101,077

Note 7. Long-Term Debt

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

	September 30,		December 31,
	2021		2020
	(In thousands)
Revolving Credit Facility (1)	$	230,000	$	255,000
Paycheck Protection Program loan (2)		—		5,516
Total long-term debt	$	230,000	$	260,516

(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 and forgiveness of the paycheck protection program loan.

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 $245.0 million as of September 30, 2021, 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.

On June 16, 2021, the Company completed its scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was decreased from $260.0 million to $245.0 million. In addition to the redetermination, the administrative agent under the Revolving Credit Facility agreement was changed from Bank of Montreal to KeyBank.

As of September 30, 2021, we were in compliance with all the financial (current ratio and total leverage ratio) and non-financial covenants associated with our Revolving Credit Facility.

On November 10, 2021, the Company completed its scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was reaffirmed at $245.0 million; provided that, beginning on February 28, 2022, the borrowing base will be reduced by $5.0 million per month on the last calendar day of each month until the next regularly scheduled redetermination, which is expected to occur in April 2022.

20

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
Revolving Credit Facility	3.64	%	3.72	%	3.65	%	3.61	%

Letters of Credit

At September 30, 2021, we had no letters of credit outstanding.

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with our Revolving Credit Facility was $1.1 million at September 30, 2021.

Paycheck Protection Program

On April 24, 2020, the Company received a $5.5 million PPP Loan. The PPP Loan was established as part of the CARES Act to provide loans to qualifying businesses. The PPP Loan was not part of the Revolving Credit Facility as described above. The loan and accrued interest were potentially forgivable provided that the borrower uses the loan proceeds for eligible purposes. The term of the Company’s PPP Loan was two years with an annual interest rate of 1% and no payments of principal or interest due during the six-month period beginning on the date of the PPP Loan. The Company applied for forgiveness of the amount due on the PPP Loan based on spending the loan proceeds on eligible expenses as defined by the statute. On June 22, 2021, KeyBank notified the Company that the PPP Loan had been approved for full and complete forgiveness by the Small Business Association. For the nine months ended September 30, 2021, the company reported a gain on extinguishment of debt of $5.5 million for the PPP Loan forgiveness in the Unaudited Condensed Consolidated Statements of Operations.

Note 8. 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 nine months ended September 30, 2021:

	Common Stock
Balance, December 31, 2020	37,663,509
Restricted stock units vested	42,534
Bonus stock awards (1)	455,973
Shares withheld for taxes (2)	(165,042)
Balance, September 30, 2021	37,996,974

(1) Reflects shares granted to certain executive officers and employees pursuant to our annual incentive bonus program. Shares were granted on February 12, 2021 at a grant price of $2.48 per share.

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

21

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Warrants

On May 4, 2017, Legacy Amplify entered into a warrant agreement with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which Legacy Amplify issued warrants to purchase up to 2,173,913 shares of Legacy Amplify’s common stock, exercisable for a five-year period commencing on May 4, 2017 at an exercise price of $42.60 per share.

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 subsequently suspended quarterly dividends. Future dividends, if any, are subject to debt covenants under our Revolving Credit Facility and discretionary approval by the board of directors.

Note 9. 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 Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
Net loss	$	(13,470)	$	(17,685)	$	(67,821)	$	(426,220)
Less: Net income allocated to participating restricted stockholders		—		—		—		—
Basic and diluted earnings available to common stockholders	$	(13,470)	$	(17,685)	$	(67,821)	$	(426,220)
Common shares:
Common shares outstanding — basic		37,996		37,626		37,937		37,596
Dilutive effect of potential common shares		—		—		—		—
Common shares outstanding — diluted		37,996		37,626		37,937		37,596
Net earnings (loss) per share:
Basic	$	(0.35)	$	(0.47)	$	(1.79)	$	(11.34)
Diluted	$	(0.35)	$	(0.47)	$	(1.79)	$	(11.34)
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 10. Long-Term Incentive Plans

In May 2021, the shareholders approved a new Equity Incentive Plan (“EIP”) in which the Legacy Amplify Management Incentive Plan (the “Legacy Amplify MIP”) and the Legacy Amplify 2017 Non-Employee Directors Compensation Plan (the “Legacy Amplify Non-Employee Directors Compensation Plan”) were replaced by the EIP and no further awards will be allowed to be granted under the Legacy Amplify MIP or the Legacy Amplify Non-Employee Directors Compensation Plan. As of September 30, 2021, an aggregate of 2,674,808 shares were available for future grants under the EIP.

22

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 $3.0 million at September 30, 2021. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.2 years.

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

		Weighted-
		Average Grant-
	Number of	Date Fair Value
	Units	per Unit (1)
TSUs outstanding at December 31, 2020	115,797	$	4.47
Granted (2)	1,065,481	$	3.63
Forfeited	(13,822)	$	4.33
Vested	(36,969)	$	4.37
TSUs outstanding at September 30, 2021	1,130,487	$	3.68

(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 nine months ended September 30, 2021 was $3.9 million based on a grant date market price ranging from $3.52 to $4.12 per share.

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 less than $0.1 million at September 30, 2021. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.3 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.

23

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2020	214,554	$	2.36
Granted	—	$	—
Forfeited	(56,010)	$	2.16
Vested	—	$	—
PSUs outstanding at September 30, 2021	158,544	$	2.43

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

Restricted Stock Units with Market Vesting Conditions

The restricted stock units with performance-based vesting conditions (“PRSUs”) 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 PRSUs are issued collectively in separate tranches with individual performances periods beginning in January 2021, 2022, and 2023 respectively. For each of the performance periods the awards will vest based on the percentage of the target PRSUs subject to the performance vesting condition with 25% able to vest during the period January 1, 2021 through December 31, 2021; 25% able to vest during the period January 1, 2022 through December 31, 2022 and 50% able to vest during the period of January 1, 2023 through December 31, 2023. Vesting of PRSUs can range from zero to 200% of the target units granted based on the Company’s relative total shareholder return as compared to the total shareholder return of the Company’s performance peer group over the performance period. The fair value of each PRSU award was estimated on their grant dates using a Monte Carlo simulation. The unrecognized cost associated with the PRSUs was $0.2 million at September 30, 2021. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.0 years.

The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2021 are presented as follows:

	2021
Expected volatility	119.6	%
Dividend yield	0.00	%
Risk-free interest rate	0.31	%

24

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

		Weighted-
		Average Grant-
	Number of	Date Fair Value
	Units	per Unit (1)
PRSUs outstanding at December 31, 2020	—	$	—
Granted (2)	196,377	$	1.94
Forfeited	—	$	—
Vested	—	$	—
PRSUs outstanding at September 30, 2021	196,377	$	1.94

(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 PRSUs issued for the nine months ended September 30, 2021 was $0.4 million based on a grant-date market price ranging from $1.24 to $2.63 per share.

2017 Non-Employee Directors Compensation Plan

In June 2017, Legacy Amplify implemented the 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. As noted above, the Legacy Amplify Non-Employee Directors Compensation Plan was replaced by the EIP in May 2021.

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 September 30, 2021. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 0.6 years.

The following table summarizes information regarding the 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, 2020	8,898	$	5.12
Granted	—	$	—
Forfeited	—	$	—
Vested	(5,565)	$	5.12
Board RSUs outstanding at September 30, 2021	3,333	$	5.12

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

25

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Compensation Expense

The following table summarizes the amount of recognized compensation expense associated with the Legacy Amplify MIP and Legacy Amplify Non-Employee Directors Compensation Plan, which are reflected in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods presented (in thousands):

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
Equity classified awards
TSUs		466		59		1,123		184
PSUs		(55)		30		(15)		69
Board RSUs		4		4		12		15
PRSUs		45		—		134		—
	$	460	$	93	$	1,254	$	268

Note 11. Leases

For the quarter ended September 30, 2021, our leases qualify as operating leases and we did not have any 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 warehouse space, vehicles, compressors and surface rentals related to our business operations. In addition, we have offshore Southern California pipeline right-of-way use agreements. Most of our leases, other than our corporate office lease, have an initial term and may be extended on a month-to-month basis after expiration of the initial term. Most of our leases can be terminated with 30-day prior written notice. The majority of our month-to-month leases are not included as a lease liability in our balance sheet under ASC 842 because continuation of the lease is not reasonably certain. Additionally, the Company elected the short-term practical expedient to exclude leases with a term of twelve months or less.

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

For the nine months ended September 30, 2021 and 2020, we recognized approximately $2.0 million and $1.8 million, respectively, of costs relating to the operating leases in the Unaudited Condensed Consolidated Statements of Operations.

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

	For the Nine Months Ended
	September 30,
	2021		2020
	(In thousands)
Non-cash amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	879	$	1,351

26

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	September 30,		December 31,
	2021		2020
	(In thousands)
Right-of-use asset	$	3,379	$	2,500
Lease liabilities:
Current lease liability		1,281		2,258
Long-term lease liability		2,132		266
Total lease liability	$	3,413	$	2,524

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 and	Leased vehicles
		warehouse	and office
	leases		equipment		Total
Remaining 2021	$	532	$	166	$	698
2022		636		327		963
2023		495		195		690
2024 and thereafter		1,280		14		1,294
Total lease payments		2,943		702		3,645
Less: interest		211		21		232
Present value of lease liabilities	$	2,732	$	681	$	3,413

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

	September 30,
	2021		2020
Weighted average remaining lease term (years):
Office and warehouse space	3.15		0.91
Vehicles	0.31		0.41
Office equipment	—		0.05
Weighted average discount rate:
Office leases	3.05	%	3.41	%
Vehicles	0.63	%	0.97	%
Office equipment	0.04	%	0.17	%

27

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 12. 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):

	September 30,		December 31,
	2021		2020
Accrued lease operating expense	$	10,185	$	8,978
Accrued capital expenditures		4,350		173
Accrued commitment fee and other expense		3,917		4,404
Accrued production and ad valorem tax		3,817		2,601
Accrued general and administrative expense		3,630		3,349
Operating lease liability		1,281		2,258
Asset retirement obligations		747		424
Accrued current income taxes		—		110
Other		311		380
Accrued liabilities	$	28,238	$	22,677

Supplemental Cash Flows

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

	For the Nine Months Ended
	September 30,
	2021		2020
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	6,578	$	7,921
Cash paid for reorganization items, net		6		532
Cash paid for taxes		—		85
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		4,177		(4,016)

Note 13. Related Party Transactions

Related Party Agreements

There have been no transactions between us and any related person in which the related person had a direct or indirect material interest for the three or nine months ended September 30, 2021 and 2020, respectively.

Note 14. Commitments and Contingencies

Litigation and Environmental

As of  September 30, 2021, we had no material contingent liabilities recorded in our Unaudited Condensed Consolidated Financial Statements associated with any litigation, pending or threatened.

Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.

28

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At September 30, 2021 and December 31, 2020, we had no environmental reserves recorded in our Unaudited Condensed Consolidated Balance Sheet.

Southern California Pipeline Incident

As of November 5, 2021, the Company and certain of its subsidiaries are named defendants in approximately 13 putative class action suits filed in the United States District Court for the Central District of California and one complaint for damages was filed against the Company and one subsidiary in the Superior Court of the State of California, County of Orange - Civil Division, which were removed to the United States District Court for the Central District of California. All of the actions generally allege that the Company caused a discharge of oil off the Southern California coast in early October 2021 and the plaintiffs seek unspecified monetary damages and certain plaintiffs seek various forms of injunctive relief. The Company understands that certain plaintiffs intend to file one or more amended consolidated complaints, and the matters may be consolidated into a single action. Regarding all 14 matters, the Company denies the allegations and intends to vigorously defend against them. As of November 5, 2021, there have been no responsive pleadings filed, discovery schedules ordered, or trial dates set in any of the 14 matters. We are also participating in a related claims process organized under the Oil Pollution Act of 1990, 33 U.S.C. S 2701 et seq. (“OPA 90”). Under OPA 90, a party alleged to be responsible for a discharge of oil is required to establish a claims process to pay for interim costs and damages as a result of the discharge. The OPA 90 claims process remains at a preliminary stage.

Future litigation may be necessary, among other things, to defend ourselves by determining the scope, enforceability, and validity of claims. The results of any current or future litigation cannot be predicted with certainty, and regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources, and other factors.

Minimum Volume Commitment

The Company is party to a gas purchase, gathering and 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 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 this contractual provision. The commitment fee expense for the three and nine months ended September 30, 2021, was approximately $0.4 million and $1.2 million, respectively. The minimum volume commitment for Oklahoma ends on June 30, 2023.

The Company is party to a gas purchase, gathering and processing contract in East Texas, which includes certain minimum gas commitments. The Company is not meeting the minimum volume required under this contractual provision. The commitment fee expense for the three and nine months ended September 30, 2021, was approximately $0.5 million and $1.5 million, respectively. The minimum volume commitment for East Texas ends on November 30, 2022.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

Beta Operating Company, LLC (“Beta”), a wholly-owned subsidiary of the Company, has an obligation with the BOEM in connection with its 2009 acquisition of the Company’s 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 as of September 30, 2021.

Note 15. Income Taxes

The Company had no income tax expense for the three and nine months ended September 30, 2021, respectively. The Company had no income tax expense for the three months ended September 30, 2020 and had less than $0.1 million in income tax expense for the nine months ended September 30, 2020. The Company’s effective tax rate was 0% for the three and nine months ended September 30, 2021, and 0% for the three and nine months ended September 30, 2020. The effective tax rates for the three and nine months ended September 30, 2021 and 2020 are different from the statutory U.S. federal income tax rate primarily due to our recorded valuation allowances.

29

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In March 2021, the President of the United States signed the ARP Act, to respond to the COVID-19 emergency and address its economic effects. The ARP Act did not have a material impact on the Company’s current year tax provision.

Note 16. Subsequent Events

Southern California Pipeline Incident

On October 2, 2021, contractors operating under the direction of Beta, a subsidiary of Amplify, observed an oil sheen on the water approximately four miles off the coast of Newport Beach, California (the “Incident”). Beta platform personnel were notified and promptly initiated the Company’s Oil Spill Response Plan, which was reviewed and approved by the Bureau of Safety and Environmental Enforcement’s Oil Spill Preparedness Division within the United States Department of the Interior, and which included the required notifications of specified regulatory agencies. On October 3, 2021, a Unified Command, consisting of the Company, the U.S. Coast Guard and California Department of Fish and Wildlife’s Office of Spill Prevention and Response, was established to respond to the Incident. The Company is and has been fully committed to working cooperatively within the Unified Command and with all relevant agencies to respond to the Incident and supporting all associated ongoing investigations.  

On October 5, 2021, the Unified Command announced that reports from its contracted commercial divers and Remotely Operated Vehicle footage indicated that a 4,000-foot section of the Company’s pipeline had been displaced with a maximum lateral movement of approximately 105 feet and that the pipeline had a 13-inch split, running parallel to the pipe. On October 14, 2021, the U.S. Coast Guard announced that it had a high degree of confidence the size of the release was approximately 588 barrels of oil, which is below the previously reported maximum estimate of 3,134 barrels. On October 16, 2021, the U.S. Coast Guard announced that it had identified the Mediterranean Shipping Company (DANIT) as a “vessel of interest” in connection with an anchor-dragging incident, which occurred in close proximity to the Company’s pipeline, and that additional vessels of interest continue to be investigated. The cause, timing and details regarding the Incident are currently under investigation and any information regarding the Incident is preliminary.

Following the Incident, the Company deployed contractors so that at the height of the Incident response there were over 1,800 personnel working under the guidance and at the direction of the Unified Command to aid in cleanup operations. As of October 14, 2021, all beaches that had been closed following the Incident have reopened. On October 15, 2021, the Unified Command announced that reports from trained oil observers and beach cleanup contractors working for the Unified Command showed significant progress in cleanup operations. On October 18, 2021, the Unified Command stated that segments of beach are recommended for no further clean-up activities. While the Unified Command has significantly reduced the number of personnel conducting remediation activities from the height of the effort, remediation efforts remain ongoing at November 15, 2021.

The Company is currently subject to a number of ongoing investigations related to the Incident by certain federal and state agencies. The outcomes of these investigations and the nature of any remedies pursued will depend on the discretion of the relevant authorities and may result in regulatory or other enforcement actions, as well as civil and criminal liability.

As of November 5, 2021, the Company and certain of its subsidiaries were named defendants in approximately 13 putative class action suits filed in the United States District Court for the Central District of California, and one complaint for damages was filed against the Company and one of its subsidiaries in the Superior Court of the State of California, County of Orange - Civil Division, which was removed to the United States District Court for the Central District of California. All of the actions generally allege that the Company caused a discharge of oil off the Southern California coast in early October 2021. The plaintiffs seek unspecified monetary damages, and certain plaintiffs seek various forms of injunctive relief. The Company understands that certain plaintiffs intend to file one or more amended consolidated complaints, and the matters may be consolidated into a single action. Regarding all 14 matters, the Company denies the allegations and intends to vigorously defend against them. As of November 5, 2021, there have been no responsive pleadings filed, discovery schedules ordered, or trial dates set in any of the 14 matters.

30

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Under the OPA 90, the Company’s pipeline was designated by the United States Coast Guard as the source of the oil discharge and therefore the Company is financially responsible for remediation and for certain costs and economic damages as provided for in OPA 90, as well as certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages. The Company is currently processing covered claims under OPA 90 as expeditiously as possible. The Company may, in the future, seek contribution from any third parties, including any vessels that may have played a role in the causes of the Incident, that are liable or potentially liable under OPA or any other law in connection with the Incident.

The Company is unable to estimate total costs for remediation efforts with respect to the Incident because remediation and related activity are still ongoing and because the evaluation and approval of certain incurred third-party and contractor claims related to remediation efforts are in progress. As of November 11, 2021, the Company has paid approximately $17.3 million in costs related to remediation efforts regarding the Incident, of which $3.8 million has been received as a reimbursement by our insurance carriers and the remaining $13.5 million has been approved for reimbursement by our insurance carriers, less the applicable deductible.

There is substantial uncertainty surrounding the full impact that the Incident will have on the Company’s financial condition and cash flow generation going forward. The Company has incurred and will continue to incur costs as a result of the Incident, and the Company anticipates that the suspension of production from Beta will lead to a material reduction in revenue from these assets. The Company carries customary industry insurance policies, including loss of production income insurance, which it expects will cover a material portion of the total aggregate costs associated with the Incident, including loss of revenue resulting from suspended operations.  However, the Company can provide no assurance that its coverage will adequately protect it against liability from all potential consequences, damages and losses related to the Incident. Given the timing of the Incident, no obligation related to the Incident was recorded for the quarter ended September 30, 2021. Additionally, due to the limited time that has elapsed since the Incident, the ongoing remediation efforts and the progress of current investigations, the Company cannot reasonably estimate the total aggregate costs related to the Incident at this time.

In accordance with customary industry practice, the Company maintains insurance against many potential losses or liabilities arising from our operations and at costs that the Company believes to be economic. The Company regularly reviews its risk of loss and the cost and availability of insurance and revises its insurance accordingly. The Company’s insurance does not cover every potential risk associated with our operations. While the Company expects its insurance policies will cover a material portion of the total aggregate costs associated with the Incident, including defense costs and loss of revenue resulting from suspended operations, the Company can provide no assurance that its coverage will adequately protect it against liability from all potential consequences, damages and losses related to the Incident and such view and understanding is preliminary and subject to change.

In response to the Incident, all operations have been suspended and the pipeline has been shut-in until the Company receives the required regulatory approvals to begin operations. On October 4, 2021, the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS) issued a Corrective Action Order (CAO) pursuant to 49 U.S.C. § 60112, which makes clear that no restart of the affected pipeline may occur until PHMSA has approved a written restart plan. The Company is working expeditiously and cooperatively to comply with the requirements of the CAO in order to gain such approvals and any other regulatory approvals that are necessary to restart operations. At present, given that the pipeline to shore is not operational, no operations are underway in the Beta field.

31

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Unaudited Condensed Consolidated Financial Statements and accompanying notes in “Item 1. Financial Statements” contained herein and in “Item 1A. Risk Factors” of our Annual Report on the Form 10-K for the year ended December 31, 2020 (“2020 Form 10-K”). The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.

Overview

We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on the reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are located in Oklahoma, the Rockies, federal waters offshore Southern California, East Texas / North Louisiana and the Eagle Ford. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.

Industry Trends and Outlook

In March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic. The nature of COVID-19 led to worldwide shutdowns, reductions in commercial and interpersonal activity and changes in consumer behavior. In attempting to control the spread of COVID-19, governments around the world imposed laws and regulations such as shelter-in-place orders, quarantines, executive orders and similar restrictions. As a result, the global economy had been marked by significant slowdown and uncertainty, which in turn led to a precipitous decline in commodity prices in response to decreased demand, further exacerbated by certain actions taken by members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”) beginning in the first quarter of 2020 that maintained high levels of global oil production. As of the first quarter of 2021, commodity prices have recovered to pre-pandemic levels, due in part to the accessibility of vaccines, reopening of economies after the lockdown, and optimism about the economic recovery. The continued spread of COVID-19, including vaccine resistant strains, or repeated deterioration in oil and natural gas prices could result in additional adverse impacts on the Company’s results of operations, cash flows and financial position, including further asset impairments.

Recent Developments

Southern California Pipeline Incident

On October 2, 2021, contractors operating under the direction of Beta Operating Company, LLC (“Beta”), one of our subsidiaries, observed an oil sheen on the water approximately four miles off the coast of Newport Beach, California (the “Incident”). Beta platform personnel were notified and promptly initiated our Oil Spill Response Plan, which was reviewed and approved by the Bureau of Safety and Environmental Enforcement’s Oil Spill Preparedness Division within the United States Department of the Interior, and which included the required notifications of specified regulatory agencies. On October 3, 2021, a Unified Command, consisting of the Company, the U.S. Coast Guard and California Department of Fish and Wildlife’s Office of Spill Prevention and Response, was established to respond to the Incident. We are and have been fully committed to working cooperatively within the Unified Command and with all relevant agencies to respond to the Incident and supporting all associated ongoing investigations.  

32

On October 5, 2021, the Unified Command announced that reports from its contracted commercial divers and Remotely Operated Vehicle footage indicated that a 4,000-foot section of our pipeline had been displaced with a maximum lateral movement of approximately 105 feet and that the pipeline had a 13-inch split, running parallel to the pipe. On October 14, 2021, the U.S. Coast Guard announced that it had a high degree of confidence the size of the release was approximately 588 barrels of oil, which is below the previously reported maximum estimate of 3,134 barrels. On October 16, 2021, the U.S. Coast Guard announced that it had identified the Mediterranean Shipping Company (DANIT) as a “vessel of interest” in connection with an anchor-dragging incident, which occurred in close proximity to our pipeline, and that additional vessels of interest continue to be investigated. The cause, timing and details regarding the Incident are currently under investigation and any information regarding the Incident is preliminary.

Following the Incident, we deployed contractors so that at the height of the Incident response there were over 1,800 personnel working under the guidance and at the direction of the Unified Command to aid in cleanup operations. As of October 14, 2021, all beaches that had been closed following the Incident have reopened. On October 15, 2021, the Unified Command announced that reports from trained oil observers and beach cleanup contractors working for the Unified Command showed significant progress in cleanup operations. On October 18, 2021, the Unified Command stated that segments of beach are recommended for no further clean-up activities. While the Unified Command has significantly reduced the number of personnel conducting remediation activities from the height of the effort, remediation efforts remain ongoing at November 15, 2021.

We are currently subject to a number of ongoing investigations related to the Incident by certain federal and state agencies. The outcomes of these investigations and the nature of any remedies pursued will depend on the discretion of the relevant authorities and may result in regulatory or other enforcement actions, as well as civil and criminal liability.

As of November 5, 2021, we and certain of our subsidiaries were named defendants in approximately 13 putative class action suits filed in the United States District Court for the Central District of California, and one complaint for damages was filed against us and one of our subsidiaries in the Superior Court of the State of California, County of Orange - Civil Division, which we removed to the United States District Court for the Central District of California. All of the actions generally allege that we caused a discharge of oil off the Southern California coast in early October 2021. The plaintiffs seek unspecified monetary damages, and certain plaintiffs seek various forms of injunctive relief. We understand that certain plaintiffs intend to file one or more amended consolidated complaints, and the matters may be consolidated into a single action. Regarding all 14 matters, we deny the allegations and intends to vigorously defend against them. As of November 5, 2021, there have been no responsive pleadings filed, discovery schedules ordered, or trial dates set in any of the 14 matters. We are also participating in a related claims process organized under the Oil Pollution Act of 1990, 33 U.S.C. S 2701 et seq. (“OPA 90”).

Future litigation may be necessary, among other things, to defend ourselves by determining the scope, enforceability, and validity of claims. The results of any current or future litigation cannot be predicted with certainty, and regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources, and other factors.

Under the OPA 90, our pipeline was designated by the United States Coast Guard as the source of the oil discharge and therefore we are financially responsible for remediation and for certain costs and economic damages as provided for in OPA 90, as well as certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages. We are currently processing covered claims under OPA 90 as expeditiously as possible. We may, in the future, seek contribution from any third parties, including any vessels that may have played a role in the causes of the Incident, that are liable or potentially liable under OPA or any other law in connection with the Incident.

For additional discussion of the legal proceedings associated with the Incident, see “Part I - Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II - Item 1A. Risk Factors — Risks Related to the Southern California Pipeline Incident.”

We are unable to estimate total costs for remediation efforts with respect to the Incident because remediation and related activity are still ongoing and because the evaluation and approval of certain incurred third-party and contractor claims related to remediation efforts are in progress. As of November 11, 2021, we have paid or authorized to pay approximately $17.3 million in costs related to remediation efforts regarding the Incident, of which $3.8 million has been received as a reimbursement by our insurance carriers and the remaining $13.5 million has been approved for reimbursement by our insurance carriers, less the applicable deductible.

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There is substantial uncertainty surrounding the full impact that the Incident will have on our financial condition and cash flow generation going forward. We have incurred and will continue to incur costs as a result of the Incident, and we anticipate that the suspension of production from Beta will lead to a material reduction in revenue from these assets.  We carry customary industry insurance policies, including loss of production income insurance, which we expect will cover a material portion of the total aggregate costs associated with the Incident, including loss of revenue resulting from suspended operations.  However, we can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses related to the Incident. Given the timing of the Incident, no obligation related to the Incident was recorded for the quarter ended September 30, 2021. Additionally, due to the limited time that has elapsed since the Incident, the ongoing remediation efforts, and the progress of current investigations, we cannot reasonably estimate the total aggregate costs related to the Incident at this time. For additional discussion of the risks associated with the Incident, see “Item 1A. Risk Factors — Risks Related to the Southern California Pipeline Incident.”

In accordance with customary insurance practice, we maintain insurance policies, including loss of production income insurance, against many potential losses or liabilities arising from our operations and at costs that we believe to be economic. We regularly review our risk of loss and the cost and availability of insurance and revise our insurance accordingly. Our insurance does not cover every potential risk associated with our operations. While we expect our insurance policies will cover a material portion of the total aggregate costs associated with the Incident, including defense costs and loss of revenue resulting from suspended operations, we can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses related to the Incident and such view and understanding is preliminary and subject to change.

In response to the Incident, all operations have been suspended and the pipeline has been shut-in until the we receive the required regulatory approvals to begin operations. On October 4, 2021, the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS) issued a Corrective Action Order (CAO) pursuant to 49 U.S.C. § 60112, which makes clear that no restart of the affected pipeline may occur until PHMSA has approved a written restart plan. We are working expeditiously and cooperatively to comply with the requirements of the CAO in order to gain such approvals and any other regulatory approvals that are necessary to restart operations. At present, given that the pipeline to shore is not operational, no operations are underway in the Beta field.

Borrowing Base Reaffirmation

On November 10, 2021, we completed our scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was reaffirmed at $245.0 million; provided that, beginning on February 28, 2022, the borrowing base will be reduced by $5.0 million per month on the last calendar day of each month until the next regularly scheduled redetermination, which is expected to occur in April 2022.

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

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Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2020 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the use of professional judgment and involve complex analysis.

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

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Results of Operations

The results of operations for the three and nine months ended September 30, 2021 and 2020 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 Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
	($ In thousands except per unit amounts)
Oil and natural gas sales	$	96,841	$	52,488	$	249,510	$	145,163
Lease operating expense		34,486		27,639		92,045		91,190
Gathering, processing and transportation		5,047		5,256		14,676		14,998
Taxes other than income		6,024		3,761		15,708		9,942
Depreciation, depletion and amortization		7,000		7,950		21,736		31,129
Impairment expense		—		—		—		455,031
General and administrative expense		6,448		6,443		19,399		21,551
Accretion of asset retirement obligations		1,665		1,565		4,918		4,617
Loss (gain) on commodity derivative instruments		46,653		14,352		145,139		(74,196)
Interest expense, net		(3,078)		(3,362)		(9,327)		(17,218)
Gain on extinguishment of debt		—		—		5,516		—
Income tax expense		—		—		—		(85)
Net loss		(13,470)		(17,685)		(67,821)		(426,220)
Oil and natural gas revenues:
Oil sales	$	63,172	$	36,868	$	169,377	$	101,682
NGL sales		11,839		5,537		28,386		14,002
Natural gas sales		21,830		10,083		51,747		29,479
Total oil and natural gas revenues	$	96,841	$	52,488	$	249,510	$	145,163
Production volumes:
Oil (MBbls)		939		997		2,763		2,294
NGLs (MBbls)		369		430		1,080		1,319
Natural gas (MMcf)		6,023		6,706		17,944		21,149
Total (MBoe)		2,312		2,545		6,833		7,768
Average net production (MBoe/d)		25.1		27.7		25.0		28.3
Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	67.30	$	36.98	$	61.30	$	34.78
NGL (per Bbl)		32.05		12.89		26.30		10.62
Natural gas (per Mcf)		3.62		1.50		2.88		1.39
Total (per Boe)	$	41.89	$	20.63	$	36.51	$	18.69
Average unit costs per Boe:
Lease operating expense	$	14.92	$	10.86	$	13.47	$	11.74
Gathering, processing and transportation		2.18		2.07		2.15		1.93
Taxes other than income		2.61		1.48		2.30		1.28
General and administrative expense		2.79		2.53		2.84		2.77
Depletion, depreciation and amortization		3.03		3.12		3.18		4.01

For the Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020

Net losses of $13.5 million and $17.7 million were recorded for the three months ended September 30, 2021 and 2020, respectively.

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Oil, natural gas and NGL revenues were $96.8 million and $52.5 million for the three months ended September 30, 2021 and 2020, respectively. Average net production volumes were approximately 25.1 MBoe/d and 27.7 MBoe/d for the three months ended September 30, 2021 and 2020, respectively. The change in production volumes was primarily due to natural decline. The average realized sales price was $41.89 per Boe and $20.63 per Boe for the three months ended September 30, 2021 and 2020, respectively. The increase in average realized sales price was primarily due to the increase in commodity prices. Commodity prices were depressed in the third quarter of 2020 due to the impact of the pandemic and the effects of OPEC production related to supply and demand decisions.

Lease operating expense was $34.5 million and $27.6 million for the three months ended September 30, 2021 and 2020, respectively. The change in lease operating expense is primarily due to platform structure inspections at our Beta properties which are performed approximately every 10 years and increase workover expenses. On a per Boe basis, lease operating expense was $14.92 and $10.86 for the three months ended September 30, 2021 and 2020, respectively. The increase in lease operating expense on a per Boe basis is primarily driven by higher costs and lower production.

Gathering, processing and transportation was $5.0 million and $5.3 million for the three months ended September 30, 2021 and 2020, respectively. On a per Boe basis, gathering, processing and transportation was $2.18 and $2.07 for the three months ended September 30, 2021 and 2020, respectively. The change in gathering, processing and transportation on a per Boe basis is due to higher costs and lower production.

Taxes other than income were $6.0 million and $3.8 million for the three months ended September 30, 2021 and 2020, respectively. The increase in taxes other than income is due to an increase in production taxes as a result of the increase in commodity prices. On a per Boe basis, taxes other than income were $2.61 and $1.48 for the three months ended September 30, 2021 and 2020, respectively. The change in taxes other than income on a per Boe basis was primarily due to the increase in commodity prices.

Depreciation, depletion & amortization (“DD&A expense”) was $7.0 million and $8.0 million for the three months ended September 30, 2021 and 2020, respectively. The change in DD&A expense was primarily due to a decrease in production from natural decline.

Impairment expense. No impairment expense recorded for the three months ended September 30, 2021 and 2020, respectively.

General and administrative expense was $6.4 million and $6.4 million for the three months ended September 30, 2021 and 2020, respectively. The change in general and administrative expense was primarily related to a decrease of $0.3 million in legal expenses and a decrease of $0.1 million in professional services partially offset by an increase of $0.3 million in stock compensation expense.

Net losses (gains) on commodity derivative instruments of $46.7 million were recognized for the three months ended September 30, 2021, consisting of $24.1 million decrease in the fair value of open positions and $22.6 million of cash settlements paid on expired positions. Net losses on commodity derivative instruments of $14.4 million were recognized for the three months ended September 30, 2020, consisting of a $28.4 million decrease in the fair value of open positions offset by $14.1 million of cash settlement received 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 $3.1 million and $3.4 million for the three months ended September 30, 2021 and 2020, respectively. The change in interest expense is primarily related to a decrease of $0.4 million in interest expense primarily due to lower interest rates related to our Revolving Credit Facility.

Average outstanding borrowings under our Revolving Credit Facility were $234.9 million and $274.5 million for the three months ended September 30, 2021 and 2020, respectively.

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Gain on extinguishment of debt. No gain on extinguishment of debt recorded for the three months ended September 30, 2021 and 2020.

For the Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020

Net losses of $67.8 million and $426.2 million were recorded for the nine months ended September 30, 2021 and 2020, respectively.

Oil, natural gas and NGL revenues were $249.5 million and $145.2 million for the nine months ended September 30, 2021 and 2020, respectively. Average net production volumes were approximately 25.0 MBoe/d and 28.3 MBoe/d for the nine months ended September 30, 2021 and 2020, respectively. The change in production volumes was primarily due to natural decline and the impact of Winter Storm Uri that caused a severe freeze in areas where we operate, including Texas, Oklahoma and Louisiana, resulting in shut-ins for wells, pipelines and plants for approximately two weeks in February 2021. The average realized sales price was $36.51 per Boe and $18.69 per Boe for the nine months ended September 30, 2021 and 2020, respectively. The increase in average realized sales price was primarily due to the increase in commodity prices. Commodity prices were depressed in the first half of 2020 due to the impact of the pandemic and the effects of OPEC production related to supply and demand decisions.

Lease operating expense was $92.0 million and $91.2 million for the nine months ended September 30, 2021 and 2020, respectively. The change in lease operating expense was primarily related to an increase for 2021 projects compared to 2020 offset by the employee retention credit received of $2.0 million for the first and second quarters of 2021, and natural decline in production. On a per Boe basis, lease operating expense was $13.47 and $11.74 for the nine months ended September 30, 2021 and 2020, respectively. The change in lease operating expense on a per Boe basis was due mainly to higher cost and lower production.

Gathering, processing and transportation was $14.7 million and $15.0 million for the nine months ended September 30, 2021 and 2020, respectively. The decrease in gathering, processing and transportation was primarily driven by the decrease in production in first quarter 2021 from Winter Storm Uri partially offset by additional fees from our non-operated wells offset by fee increases from our processing plants and minimum volume commitments. On a per Boe basis, gathering, processing and transportation was $2.15 and $1.93 for the nine months ended September 30, 2021 and 2020, respectively. The change in gathering, processing and transportation on a per Boe basis was due to higher costs and lower production.

Taxes other than income were $15.7 million and $9.9 million for the nine months ended September 30, 2021 and 2020, respectively. The increase in taxes other than income is due to an increase in production taxes as a result of the increase in commodity prices. On a per Boe basis, taxes other than income were $2.30 and $1.28 for the nine months ended September 30, 2021 and 2020, respectively. The change in taxes other than income on a per Boe basis was primarily due to the increase in commodity prices.

DD&A expense was $21.7 million and $31.1 million for the nine months ended September 30, 2021 and 2020, respectively. The change in DD&A expense was primarily due to a decrease in production and a decrease in our DD&A rate.

Impairment expense was $455.0 million for the nine months ended September 30, 2020. We recognized $405.7 million of impairment expense on proved properties for the nine months ended September 30, 2020. 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 in 2020. We recognized $49.3 million of impairment expense on unproved properties for the nine months ended September 30, 2020, which was related to expiring leases and the evaluation of qualitative and quantitative factors related to the decline in commodity prices in 2020. No impairment expense was recorded for the nine months ended September 30, 2021.

General and administrative expense was $19.4 million and $21.6 million for the nine months ended September 30, 2021 and 2020, respectively. The change in general and administrative expense was primarily related to (1) the employee retention credit received of $0.8 million for the first and second quarters of 2021; (2) a decrease of $0.8 million in salaries and other payroll benefits, (3) a decrease of $0.7 million in professional services, and (4) a decrease of $0.7 million in legal expenses. The decreases in general and administrative expense were offset with an increase of $1.0 million in stock compensation expense.

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Net losses (gains) on commodity derivative instruments of $145.1 million were recognized for the nine months ended September 30, 2021, consisting of $95.0 million decrease in the fair value of open positions and $50.1 million of cash settlements paid on expired positions. Net gains on commodity derivative instruments of $74.2 million were recognized for the nine months ended September 30, 2020, consisting of $2.3 million increase in the fair value of open positions and $53.9 million of cash settlement paid on expired positions and $18.0 million of cash settlements received on terminated positions.

Interest expense, net was $9.3 million and $17.2 million for the nine months ended September 30, 2021 and 2020, respectively. Interest expense included $0.5 million and $3.1 million for the amortization and write-off of deferred financing costs for the nine months ended September 30, 2021 and 2020, respectively. Furthermore, we had a loss position on our interest rate swaps of less than $0.1 million for the nine months ended September 30, 2021, compared to a loss position on interest rate swaps of $4.0 million for the nine months ended September 30, 2020. In addition, we had a decrease of $1.1 million in interest expense due to lower borrowings on our Revolving Credit Facility.

Average outstanding borrowings under our Revolving Credit Facility were $243.6 million and $285.6 million for the nine months ended September 30, 2021 and 2020, respectively.

Gain on extinguishment of debt was $5.5 million for the nine months ended September 30, 2021 which is related to the forgiveness of the PPP Loan. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding the PPP Loan.

Adjusted EBITDA

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

Plus:

● Interest expense;

● Income tax expense;

● 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;

● Amortization of gain associated with terminated commodity derivatives;

● Losses on sale of assets;

● Share-based compensation expenses;

● Exploration costs;

● Acquisition and divestiture related expenses;

● Reorganization items, net;

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

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

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

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Reconciliation of Net Income (Loss) to Adjusted EBITDA

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
	(In thousands)
Net income (loss)	$	(13,470)	$	(17,685)	$	(67,821)	$	(426,220)
Interest expense, net		3,078		3,362		9,327		17,218
Income tax expense		—		—		—		85
DD&A		7,000		7,950		21,736		31,129
Impairment expense		—		—		—		455,031
Accretion of AROs		1,665		1,565		4,918		4,617
Losses (gains) on commodity derivative instruments		46,653		14,352		145,139		(74,196)
Cash settlements received (paid) on expired commodity derivative instruments		(22,595)		14,067		(50,086)		53,862
Amortization of gain associated with terminated commodity derivatives		4,066		—		14,017		—
Acquisition and divestiture related expenses		—		152		19		677
Share-based compensation expense		676		456		1,910		(84)
Exploration costs		9		5		32		24
Loss on settlement of AROs		—		113		73		113
Bad debt expense		14		218		108		469
Gain on extinguishment of debt		—		—		(5,516)		—
Reorganization items, net		—		180		6		532
Severance payments		—		25		—		54
Other		(16)		—		—		—
Adjusted EBITDA	$	27,080	$	24,760	$	73,862	$	63,311

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
	(In thousands)
Net cash provided by operating activities	$	18,884	$	20,609	$	55,287	$	63,598
Changes in working capital		783		(217)		(6,465)		5,094
Interest expense, net		3,078		3,362		9,327		17,218
Gain (loss) on interest rate swaps		(47)		20		(3)		(4,035)
Cash settlements paid (received) on interest rate swaps		485		462		1,425		786
Cash settlements paid (received) on terminated derivatives		—		—		—		(17,977)
Amortization of gain associated with terminated commodity derivatives		4,066		—		14,017		—
Amortization and write-off of deferred financing fees		(133)		(135)		(493)		(3,134)
Acquisition and divestiture related expenses		—		152		19		677
Income tax expense - current portion		—		—		—		85
Exploration costs		9		5		32		24
Plugging and abandonment cost		—		312		235		312
Reorganization items, net		—		180		6		532
Severance payments		—		25		—		54
Other		(45)		(15)		475		77
Adjusted EBITDA	$	27,080	$	24,760	$	73,862	$	63,311

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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 on hand, cash flows provided by operating activities and borrowings under our Revolving Credit Facility. For the remainder of 2021, we expect our primary funding sources to be cash flows provided by operating activities, cash on hand and available borrowing capacity under our Revolving Credit Facility.

Impact of the Southern California Pipeline Incident. There is substantial uncertainty surrounding the full impact that the Incident will have on our financial condition and cash flow generation going forward. We have incurred and will continue to incur costs as a result of the Incident, and we anticipate that the suspension of production from Beta will lead to a material reduction in revenue from these assets. Although we carry customary insurance policies, including loss of production income insurance, which we expect will cover a material portion of the total aggregate costs associated with the Incident, including loss of revenue resulting from suspended operations, we can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses related to the Incident.

Additionally, as discussed in greater detail below, on November 10, 2021, the Company completed its scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was reaffirmed at $245.0 million; provided that, beginning on February 28, 2022, the borrowing base will be reduced by $5.0 million per month on the last calendar day of each month until the next regularly scheduled redetermination, which is expected to occur in April 2022. This impact on our borrowing base may limit our liquidity position and may impact our ability to finance our operations.

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

Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 30%-65% 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 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.

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 $27.3 million for the nine months ended September 30, 2021, which were primarily related to capital workovers, maintenance and facilities located in Oklahoma, the Rockies and California and non-operated completion activities in the Eagle Ford.

Working Capital. We expect to fund our working capital needs primarily with operating cash flows. Furthermore, our expected capital expenditures and debt service requirements are expected to be funded by operating cash flows. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” and “—Overview” of this quarterly report for additional information.

As of September 30, 2021, we had a working capital deficit of $69.3 million primarily due to short-term derivatives of $83.6 million, accrued liabilities of $28.2 million, revenues payable of $21.1 million, and accounts payable of $9.2 million offset by accounts receivable of $44.7 million, cash on hand of $17.3 million and prepaid expenses of $10.7 million.

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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. 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.

On June 16, 2021, the Company completed its scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was decreased from $260.0 million to $245.0 million. Additionally, the administrative agent under the Revolving Credit Facility agreement was changed from Bank of Montreal to KeyBank.

As of September 30, 2021, we had approximately $245.0 million of available borrowings under our Revolving Credit Facility. See Note 7 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.

As of September 30, 2021, we were in compliance with all the financial (current ratio and total leverage ratio) and other covenants associated with our Revolving Credit Facility.

On November 10, 2021, the Company completed its scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was reaffirmed at $245.0 million; provided that, beginning on February 28, 2022, the borrowing base will be reduced by $5.0 million per month on the last calendar day of each month until the next regularly scheduled redetermination, which is expected to occur in April 2022. This impact on our borrowing base may limit our liquidity position and may impact our ability to finance our operations. See Note 7 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.

COVID-19 Relief Funding. On June 22, 2021, the Company was notified by the bank that the PPP Loan was approved for full and complete forgiveness by the Small Business Association. For the nine months ended September 30, 2021, the Company recorded a gain on extinguishment of debt for $5.5 million in the Unaudited Condensed Consolidated Statements of Operations.

Under the Consolidated Appropriations Act 2021 passed by the U.S. Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified making the Company eligible for the employee retention credit subject to meeting certain criteria. The Company met the criteria for the first and second quarters of 2021 and recognized a $2.8 million employee retention credit during the nine months ended September 30, 2021, which is included as a credit to general and administrative expense and to lease operating expense in the Unaudited Condensed Consolidated Statements of Operations.

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 nine months ended September 30, 2021 and 2020 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 Consolidated Statements of Cash Flows included under “Item 1. Financial Statements” of this quarterly report.

	For the Nine Months Ended
	September 30,
	2021		2020
	(In thousands)
Net cash provided by operating activities	$	55,287	$	63,598
Net cash used in investing activities		(23,253)		(32,062)
Net cash used in financing activities		(25,054)		(18,340)

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $55.3 million and $63.6 million for the nine months ended September 30, 2021 and 2020, respectively. Production volumes were approximately 25.0 MBoe/d and 28.3 MBoe/d for the nine months ended September 30, 2021 and 2020, respectively. The average realized sales price was $36.51 per Boe and $18.69 per Boe for the nine months ended September 30, 2021 and 2020, respectively. The change in average realized sales price was primarily due to the increase in commodity prices.

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Net cash provided by operating activities for the nine months ended September 30, 2021 included $51.5 million of cash paid on expired derivative instruments compared to $53.1 million of cash receipts on expired derivatives and $18.0 million of cash receipts on terminated derivative instruments for the nine months ended September 30, 2020. For the nine months ended September 30, 2021, we had net losses on derivative instruments of $145.1 million compared to a net gains of $70.2 million for the nine months ended September 30, 2020.

In addition, the Company recorded a $5.5 million gain on extinguishment of debt related to the forgiveness of the PPP Loan. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding the PPP Loan.

Investing Activities. Net cash used in investing activities for the nine months ended September 30, 2021 was $23.3 million, of which $23.1 million was used for additions to oil and natural gas properties. Net cash provided by investing activities for the nine months ended September 30, 2020 was $32.1 million, of which $31.2 million was used for additions to oil and natural gas properties.

Financing Activities. The Company had net repayments of $25.0 million and $20.0 million for the nine months ended September 30, 2021 and 2020, respectively, related to our Revolving Credit Facility.

For the nine months ended September 30, 2020, the Company paid out $3.8 million in dividends on March 30, 2020 to stockholders of record at the close of business on March 16, 2020. The board of directors subsequently suspended quarterly dividends. Future dividends, if any, are subject to debt covenants under our Revolving Credit Facility and discretionary approval by the board of directors.

As noted above, the Company received forgiveness for the $5.5 million PPP Loan received in April 2020.

Off–Balance Sheet Arrangements

As of September 30, 2021, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

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

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.

ITEM 4.CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2021.

The full impact of COVID-19 on our business is still uncertain. In order to protect the health and safety of our employees, we took proactive steps to allow employees to work remotely and to reduce the number of employees on site at any one time in our field

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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 most recent quarter.

Change in Internal Control Over Financial Reporting

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

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

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PART II—OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS.

As of November 5, 2021, we and certain of our subsidiaries are named defendants in approximately 13 putative class action suits filed in the United States District Court for the Central District of California and one complaint for damages was filed against us and one subsidiary in the Superior Court of the State of California, County of Orange - Civil Division, which we removed to the United States District Court for the Central District of California. All of the actions generally allege that we caused a discharge of oil off the Southern California coast in early October 2021 and the plaintiffs seek unspecified monetary damages and certain plaintiffs seek various forms of injunctive relief. We understand that certain plaintiffs intend to file one or more amended consolidated complaints, and the matters may be consolidated into a single action. Regarding all 14 matters, we deny the allegations and intends to vigorously defend against them. As of November 5, 2021, there have been no responsive pleadings filed, discovery schedules ordered, or trial dates set in any of the 14 matters. We are also participating in a related claims process organized under the Oil Pollution Act of 1990, 33 U.S.C. S 2701 et seq. (“OPA 90”). Under OPA 90, a party alleged to be responsible for a discharge of oil is required to establish a claims process to pay for interim costs and damages as a result of the discharge. The OPA 90 claims process remains at a preliminary stage. For additional discussion of the legal proceedings associated with the Incident, see “Part I - Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II - Item 1A. Risk Factors — Risks Related to the Southern California Pipeline Incident.”

Future litigation may be necessary, among other things, to defend ourselves by determining the scope, enforceability, and validity of claims. The results of any current or future litigation cannot be predicted with certainty, and regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources, and other factors.

ITEM 1A.RISK FACTORS.

Our business faces many risks. Any of the risks discussed elsewhere in this quarterly report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. Except with respect to the risk factors set forth below, there have been no material changes to the risk factors disclosed in Part I, Item 1A in the Company’s Annual Report on Form 10-K:

Risks Related to the Southern California Pipeline Incident

Significant uncertainties exist regarding the extent and timing of costs and liabilities relating to the Incident, and potential changes in the regulatory and operating environment in which we operate resulting from the Incident may increase the risks to which we are exposed. The duration of such uncertainties may exist for a significant period and such risks may have a material adverse impact on our business, results of operations and financial condition and the implementation of our strategic agenda. Furthermore, the risks associated with the Incident may heighten the consequences of other risks to which we are exposed, including with respect to access to financing and financial assurance.

We may be subject to significant clean-up requirements as a result of the Incident and it is not currently possible to estimate the cost of such requirements.

Remediation operations relating to the Incident are ongoing, and the extent, timing and cost of such operations, including any potential long-term environmental impact of the Incident and related remediation operations, is difficult to project. However, the costs of such remediation operations arising from the Incident may be material and could impact our business, our results of operations and could put pressure on our liquidity position going forward.

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We are subject to significant litigation and enforcement risk as a result of the Incident.

Under the OPA 90, the Company’s pipeline was designated by the United States Coast Guard as the source of the oil discharge and therefore the Company is financially responsible for remediation and for certain costs and economic damages as provided for in OPA 90. The Company is currently processing covered claims under OPA 90 as expeditiously as possible. At this time, it is not possible to estimate the total number of future claims or the full extent of compensable damages arising from the Incident.

In addition, we and certain of our subsidiaries have been named as defendants in approximately 14 lawsuits (including approximately 13 putative class actions) pending in the United States District Court for the Central District of California. The Company expects that the 13 putative class actions will be consolidated into a single consolidated action. As of October 31, 2021, there have been no responsive pleadings filed, discovery schedules ordered, or trial dates set. Additional actions are likely to be brought. Resolution of these cases may take considerable time, and it is not possible at this time to estimate our potential liability resulting from these actions.

Federal, state and municipal authorities may also to take enforcement action against us as a result of the Incident. To date, the U.S. Coast Guard, the U.S. Bureau of Ocean Energy Management, the U.S. Department of Justice, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, the U.S. Department of the Interior Bureau of Safety and Environmental Enforcement, the California Department of Justice, the Orange County District Attorney and the California Department of Fish & Wildlife are conducting investigations or examinations of the Incident. Other federal agencies may or have commenced investigations and proceedings, and federal agencies such as the U.S. Environmental Protection Agency are expected to initiate enforcement actions seeking penalties and other relief under the Clean Water Act and other statutes. The outcomes of these investigations and the nature of any remedies pursued will depend on the discretion of the relevant authorities and may result in regulatory or other enforcement actions, as well as civil and criminal liability.

Our potential liabilities resulting from pending and future claims, lawsuits and enforcement actions relating to the Incident, together with the potential cost of implementing remedies sought in the various proceedings, cannot be fully estimated at this time but they may have a material adverse impact on our business, results of operations and financial condition and the implementation of our strategic agenda. For further information, please see Note 14, “Commitments and Contingencies — Litigation and Environmental” of the Notes to Unaudited Condensed Consolidated Financial Statements and Item 1. “Legal Proceedings” included in this quarterly report.

We may be subject to increased regulatory scrutiny as a result of the Incident.

The Incident may result in more stringent regulation of oil and gas activities in federal waters off California and elsewhere, particularly relating to environmental and health and safety protection controls, oversight of oil and gas operations and required financial assurance. Regulatory or legislative action may impact the industry as a whole and could be directed specifically towards operators similarly situated to us. New regulations and legislation, as well as evolving practices, may increase the cost of compliance, require changes to our operations and strategic plans and impact our ability to capitalize on our assets.

The Incident may impact our ability to access financing on acceptable terms and may materially impact our liquidity.

The reputational consequences of the Incident, ongoing concerns surrounding costs arising from the Incident, ongoing contingencies related to the Incident and the impact of the Incident on our liquidity and financial performance, could increase our financing costs and limit our access to financing on acceptable terms. Our ability to engage in trading activities may also be impacted due to counterparty concerns about our financial and business risk profile following the Incident. Such counterparties may require that we provide collateral or other forms of financial security for their obligations. Certain counterparties for our non-trading businesses may also require that we provide collateral for certain contractual obligations.

In addition we may be unable to access liquidity under our Revolving Credit Facility in the event there are pending or threatened legal, arbitration or administrative proceedings which, if determined adversely, might reasonably be expected to have a material adverse effect on our ability to meet the payment obligations under our Revolving Credit Facility. Extended constraints on our ability to obtain financing and to engage in trading activities on acceptable terms (or at all) may put pressure on our liquidity. In addition, this could occur at a time when cash flows from our business operations may be constrained. In order to address severe liquidity constraints we could be required to further reduce capital expenditures, sell strategic assets or obtain financing on terms that could have a significant adverse effect on stockholder returns and the implementation of our strategic plans.

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We may not have adequate insurance to compensate us, and our insurers may not pay particular claims.

We currently maintain insurance that covers against certain of the losses and expenses associated with the Incident. However, we cannot guarantee that our insurance policies will cover all losses that we incur in connection with the Incident, or that disputes over insurance claims will not arise with our insurance carriers. Additionally, the insurers may not pay particular claims or may take an extended period of time to do so. In addition, our insurance policies are subject to limitations and exclusions, which may increase our costs or lower our revenues, thereby possibly having a material adverse effect on our business, results of operations and financial condition. Finally, we cannot guarantee that we will be able to renew our insurance policies on the same or commercially reasonable terms, or at all, in the future.

The shut-in of the pipeline could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance

Our production depends, in part, upon our assets that are capable of commercial production not being shut-in (i.e., suspended from production). In response to the Incident, we have shut-in the pipeline impacted by the Incident and the Beta field, which has decreased our overall production volumes. This decrease in production will impact our ability to generate cash flows from operations, and we will experience a reduction in our available liquidity, which may adversely affect our ability to meet our anticipated working capital, debt service, and other liquidity needs.

The Incident has created significant risk to our reputation and has diverted, and will continue to divert, the attention of our management team.

The Incident has damaged our reputation, which may have a long-term impact on us. Adverse public, political and industry sentiment towards us, and oil and gas activities generally, could damage or impair our existing commercial relationships with counterparties, partners and governmental agencies and could impair our access to new investment opportunities, operatorships or other essential commercial arrangements with potential partners and governmental agencies. In addition, responding to the Incident may place a significant burden on our cash flow, which could also impede our ability to invest in new opportunities and deliver long-term growth.

In addition, our response to the Incident has required significant management focus. Key management and operating personnel are, and will need to continue, devoting substantial attention to respond to the Incident and to address the associated consequences for us, leaving them less time to devote to executing our strategic plans. In addition, we rely on recruiting and retaining high quality employees to execute our strategic plans and to operate our business.  The Incident response has placed significant demands on our employees, and the reputational damage suffered by us as a result of the Incident and any consequent adverse impact on our business could affect employee recruitment and retention.

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

The following table summarizes our repurchase activity during the nine months ended September 30, 2021:

				Total Number of	Approximate Dollar
				Shares Purchased as	Value of Shares That
				Part of Publicly	May Yet Be
	Total Number of	Average Price		Announced Plans	Purchased Under the
Period	Shares Purchased	Paid per Share		or Programs	Plans or Programs (1)
					(In thousands)
Common Shares Repurchased (1)
July 1, 2021 - July 31, 2021	1,894	$	4.15	—	n/a
August 1, 2021 - August 31, 2021	1,190	$	3.36	—	n/a
September 1, 2021 - September 30, 2021	—	$	—	—	n/a

(1) Common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. The Company repurchased the remaining vesting shares on the vesting date at current market price. See Note 8 of the Notes to the Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

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ITEM 3.DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4.MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.OTHER INFORMATION.

Borrowing Base Reaffirmation

On November 10, 2021, the Company completed its scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was reaffirmed at $245.0 million; provided that, beginning on February 28, 2022, the borrowing base will be reduced by $5.0 million per month on the last calendar day of each month until the next regularly scheduled redetermination, which is expected to occur in April 2022.

The foregoing description of the Borrowing Base Redetermination Agreement and Fifth Amendment to the Credit Agreement is qualified in its entirety by reference to the Borrowing Base Redetermination Agreement and Fifth Amendment to the Credit Agreement, a copy of which is attached hereto as Exhibit 10.2 and is incorporated herein by reference.

Amendment and Restatement of Company Bylaws

On November 9, 2021, the Third Amended and Restated Bylaws of the Company (the “Third Amended and Restated Bylaws”) became effective. The Third Amended and Restated Bylaws amend and restate the Company’s bylaws in their entirety to, among other things: (i) establish procedures relating to stockholder requests for a special meeting; (ii) revise procedures and disclosure requirements for the nomination of directors and the submission of proposals by stockholders for consideration at meetings of stockholders; (iii) provide that, while members of the board of directors of the Company are elected by a majority of the shares present in person or represented by proxy at a meeting and entitled to vote therefor in the election of directors, in contested elections, members of the board of directors shall instead be elected by a plurality of the shares present in person or represented by proxy at the meeting and entitled to vote therefor in the election of directors; (iv) establish procedures relating to actions taken by stockholders by written consent, including the ability of the board of directors to fix a record date for determining the stockholders entitled to consent to certain corporate actions by the Company in writing without a meeting; (v) clarify that, consistent with Section 141(c)(2) of the Delaware General Corporation Law, the board of directors has greater flexibility to delegate authority to committees of the board of directors; and (vi) make certain administrative, clarifying and conforming changes.  

The foregoing description of the amendments made by the Third Amended and Restated Bylaws is qualified in its entirety by reference to the Third Amended and Restated Bylaws, a copy of which is attached hereto as Exhibit 3.3 and is incorporated herein by reference.

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ITEM 6.EXHIBITS.

Exhibit Number		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 Certificate of Incorporation of Midstates Petroleum Company, Inc., dated August 6, 2019 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).
3.3*	—	Third Amended and Restated Bylaws of Amplify Energy Corp.
10.1*	—	Borrowing Base Redetermination Agreement and Fifth Amendment to Credit Agreement, dated as of November 10, 2021, by and among Amplify Energy Operating LLC, Amplify Acquisitionco LLC, each of the other guarantors party thereto, each of the lenders party thereto and KeyBank National Association, as administrative agent for the lenders.
31.1*	—	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*	—	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**	—	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	Inline XBRL Instance Document
101.SCH*	—	Inline XBRL Schema Document
101.CAL*	—	Inline XBRL Calculation Linkbase Document
101.DEF*	—	Inline XBRL Definition Linkbase Document
101.LAB*	—	Inline XBRL Labels Linkbase Document
101.PRE*	—	Inline XBRL Presentation Linkbase Document
104*	—	Cover Page Interactive Data File (embedded within the Inline XBRL document)

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

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

# Management contract or compensatory plan or arrangement.

† Certain schedules and similar attachments have been omitted. We agree to furnish supplementally a copy of any omitted schedule or attachment to the SEC upon its request.

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SIGNATURES

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

		Amplify Energy Corp.
		(Registrant)
Date:	November 15, 2021	By:	/s/ Jason McGlynn
		Name:	Jason McGlynn
		Title:	Senior Vice President and Chief Financial Officer
Date:	November 15, 2021	By:	/s/ Eric Dulany
		Name:	Eric Dulany
		Title:	Vice President and Chief Accounting Officer

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