Amplify Energy (AMPY) 10-Q 2023 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2023

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 þ
Non-accelerated filer ☐	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 July 31, 2023, the registrant had 39,062,303 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 June 30, 2023 and December 31, 2022	8
	Unaudited Condensed Consolidated Statements of Net Income for the Three and Six Months Ended June 30, 2023 and 2022	9
	Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2023 and 2022	10
	Unaudited Condensed Consolidated Statements of Equity (Deficit) for the Three and Six Months Ended June 30, 2023 and 2022	11
	Notes to Unaudited Condensed Consolidated Financial Statements	12
	Note 1 – Organization and Basis of Presentation	12
	Note 2 – Summary of Significant Accounting Policies	12
	Note 3 – Revenue	13
	Note 4 – Fair Value Measurements of Financial Instruments	13
	Note 5 – Risk Management and Derivative Instruments	15
	Note 6 – Asset Retirement Obligations	17
	Note 7 – Long-Term Debt	18
	Note 8 – Equity	19
	Note 9 – Earnings per Share	20
	Note 10 – Long-Term Incentive Plans	20
	Note 11 – Leases	22
	Note 12 – Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Consolidated Statements of Cash Flows	24
	Note 13 – Related Party Transactions	25
	Note 14 – Commitments and Contingencies	25
	Note 15 – Income Taxes	27
	Note 16 – Southern California Pipeline Incident	27
	Note 17 – Subsequent Event	31
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	45
Signatures		46

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.

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

2

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 indicated otherwise:

● “Amplify Energy,” “Amplify,” “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;

● ongoing impact of the oil incident that occurred off the coast of Southern California resulting from the Company’s pipeline operations (the “Pipeline”) 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, cyber security breaches, military operations or national emergency;

● the occurrence or threat of epidemic or pandemic diseases, such as the coronavirus (“COVID-19”) pandemic that began in 2020, or any government response to such occurrence or threat;

5

● expectations regarding general economic conditions, including inflation;

● 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 the ongoing impact to the Company;

● 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;

● 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, including escalating tensions between Russia and Ukraine and the potential destabilizing effect such conflict may pose for the European continent or the global oil and natural gas markets;

● 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, including those related to climate change and hydraulic fracturing;

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

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

● 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, 2022 filed with the SEC on March 9, 2023 (“2022 Form 10-K”). All forward-looking statements speak only as of the date of this report. The Company does 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 the Company or persons acting on its behalf.

7

PART I—FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS.

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	1,865	$	—
Accounts receivable, net (see Note 12)		63,021		80,455
Prepaid expenses and other current assets		23,452		18,789
Total current assets		88,338		99,244
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		858,651		840,310
Support equipment and facilities		147,613		147,496
Other		9,801		9,648
Accumulated depreciation, depletion and amortization		(671,042)		(658,162)
Property and equipment, net		345,023		339,292
Restricted investments		15,550		11,326
Operating lease - long term right-of-use asset		6,428		7,376
Deferred tax asset		259,422		—
Other long-term assets		719		2,240
Total assets	$	715,480	$	459,478
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	23,382	$	38,414
Revenues payable		21,496		22,105
Accrued liabilities (see Note 12)		55,387		58,449
Short-term derivative instruments		735		20,884
Total current liabilities		101,000		139,852
Long-term debt (see Note 7)		120,000		190,000
Asset retirement obligations		118,627		114,614
Operating lease liability		5,818		6,567
Other long-term liabilities		11,891		13,010
Total liabilities		357,336		464,043
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 June 30, 2023 and December 31, 2022		—		—
Common stock, $0.01 par value: 250,000,000 shares authorized; 38,971,426 and 38,459,731 shares issued and outstanding at June 30, 2023 and December 31, 2022, respectively		391		386
Additional paid-in capital		432,380		432,251
Accumulated deficit		(74,627)		(437,202)
Total stockholders' equity (deficit)		358,144		(4,565)
Total liabilities and equity	$	715,480	$	459,478

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

8

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF NET INCOME

(In thousands, except per share amounts)

	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
Revenues:
Oil and natural gas sales	$	67,393	$	112,878	$	133,677	$	206,750
Other revenues		4,578		8,899		18,164		26,460
Total revenues		71,971		121,777		151,841		233,210
Costs and expenses:
Lease operating expense		34,903		33,285		67,863		66,205
Gathering, processing and transportation		5,149		7,281		10,751		15,291
Taxes other than income		5,205		8,623		10,498		16,176
Depreciation, depletion and amortization		7,072		5,864		12,880		11,499
General and administrative expense		7,778		8,628		16,292		16,399
Accretion of asset retirement obligations		1,975		1,749		3,917		3,469
Loss (gain) on commodity derivative instruments		(3,798)		18,571		(18,957)		111,975
Pipeline incident loss		6,844		5,092		15,123		5,672
Other, net		253		406		279		441
Total costs and expenses		65,381		89,499		118,646		247,127
Operating income (loss)		6,590		32,278		33,195		(13,917)
Other income (expense):
Interest expense, net		(3,701)		(3,084)		(9,438)		(5,525)
Litigation settlement (See Note 14)		—		—		84,875		—
Other income (expense)		122		26		195		48
Total other income (expense)		(3,579)		(3,058)		75,632		(5,477)
Income (loss) before income taxes		3,011		29,220		108,827		(19,394)
Income tax (expense) benefit - current		6,853		—		(5,674)		—
Income tax (expense) benefit - deferred		(48)		—		259,422		—
Net income (loss)	$	9,816	$	29,220	$	362,575	$	(19,394)
Allocation of net income (loss) to:
Net income (loss) available to common stockholders	$	9,383	$	27,818	$	346,153	$	(19,394)
Net income (loss) allocated to participating securities		433		1,402		16,422		—
Net income (loss) available to Amplify Energy Corp.	$	9,816	$	29,220	$	362,575	$	(19,394)
Earnings (loss) per share: (See Note 9)
Basic and diluted earnings (loss) per share	$	0.24	$	0.73	$	8.91	$	(0.51)
Weighted average common shares outstanding:
Basic and diluted		38,971		38,330		38,833		38,256

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

9

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	For the Six Months Ended
	June 30,
	2023		2022
Cash flows from operating activities:
Net income (loss)	$	362,575	$	(19,394)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		12,880		11,499
Loss (gain) on derivative instruments		(18,957)		111,132
Cash settlements (paid) received on expired derivative instruments		(1,192)		(79,846)
Deferred income tax expense (benefit)		(259,422)		—
Accretion of asset retirement obligations		3,917		3,469
Share-based compensation (see Note 10)		2,281		1,374
Settlement of asset retirement obligations		(289)		(389)
Amortization and write-off of deferred financing costs		771		336
Bad debt expense		85		6
Changes in operating assets and liabilities:
Accounts receivable		17,348		(4,269)
Prepaid expenses and other assets		(4,558)		(2,243)
Payables and accrued liabilities		(20,662)		9,310
Other		444		(589)
Net cash provided by operating activities		95,221		30,396
Cash flows from investing activities:
Additions to oil and gas properties		(16,772)		(12,901)
Additions to other property and equipment		(153)		—
Additions to restricted investments		(4,224)		(4,013)
Net cash used in investing activities		(21,149)		(16,914)
Cash flows from financing activities:
Advances on revolving credit facility		10,000		5,000
Payments on revolving credit facility		(80,000)		(20,000)
Deferred financing costs		(60)		(60)
Shares withheld for taxes		(2,147)		(530)
Net cash used in financing activities		(72,207)		(15,590)
Net change in cash and cash equivalents		1,865		(2,108)
Cash and cash equivalents, beginning of period		—		18,799
Cash and cash equivalents, end of period	$	1,865	$	16,691

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

10

AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (DEFICIT)

(In thousands)

	Stockholders' Equity
			Additional		Accumulated
	Common		Paid-in		Earnings
	Stock		Capital		(Deficit)		Total
Balance at December 31, 2022	$	386	$	432,251	$	(437,202)	$	(4,565)
Net income (loss)		—		—		352,759		352,759
Share-based compensation expense		—		941		—		941
Shares withheld for taxes		—		(2,141)		—		(2,141)
Other		5		(5)		—		—
Balance at March 31, 2023		391		431,046		(84,443)		346,994
Net income (loss)		—		—		9,816		9,816
Share-based compensation expense		—		1,340		—		1,340
Shares withheld for taxes		—		(6)		—		(6)
Balance at June 30, 2023	$	391	$	432,380	$	(74,627)	$	358,144

	Stockholders' Equity (Deficit)
					Additional		Accumulated
	Common				Paid-in		Earnings
	Stock		Warrants (1)		Capital		(Deficit)		Total
Balance at December 31, 2021	$	382	$	4,788	$	425,066	$	(495,077)	$	(64,841)
Net income (loss)		—		—		—		(48,614)		(48,614)
Share-based compensation expense		—		—		518		—		518
Shares withheld for taxes		—		—		(66)		—		(66)
Other		2		—		(2)		—		—
Balance at March 31, 2022		384		4,788		425,516		(543,691)		(113,003)
Net income (loss)		—		—		—		29,220		29,220
Share-based compensation expense		—		—		856		—		856
Shares withheld for taxes		—		—		(464)		—		(464)
Expiration of warrants		—		(4,788)		4,788		—		—
Other		1		—		(1)		—		—
Balance at June 30, 2022	$	385	$	—	$	430,695	$	(514,471)	$	(83,391)

(1) The warrants expired on May 4, 2022.

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,” “Amplify,” “it” or the “Company”) is a publicly traded Delaware corporation whose common stock is listed on the NYSE under the symbol “AMPY.”

The Company is engaged in the acquisition, development, exploitation and production of oil and natural gas properties located in Oklahoma, the Rockies, federal waters offshore Southern California, East Texas/North Louisiana and the Eagle Ford. 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

The Company’s accompanying Unaudited Condensed Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the Company’s opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments of a normal recurring nature necessary for fair presentation. Material intercompany transactions and balances have been eliminated.

The results reported in these Unaudited Condensed Consolidated Financial Statements are not necessarily indicative of results that may be expected for the entire year. Furthermore, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC. Accordingly, the accompanying Unaudited Condensed Consolidated Financial Statements and Notes should be read in conjunction with the Company’s annual financial statements included in its 2022 Form 10-K.

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; fair value estimates; revenue recognition; and contingencies and insurance accounting.

Note 2. Summary of Significant Accounting Policies

There have been no changes to the Company’s significant accounting policies as described in the Company’s annual financial statements included in its 2022 Form 10-K.

New Accounting Pronouncements

The Company has implemented all new accounting pronouncements that are in effect. These pronouncements did not have any material impact on the financial statements unless otherwise disclosed, and the Company does not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on its financial position or results of operations.

12

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Revenue

Revenue from Contracts with Customers

Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, (5) recognize revenue when the reporting organization satisfies a performance obligation.

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.

Disaggregation of Revenue

The Company has identified three material revenue streams in its business: oil, natural gas and NGLs. The following table presents the Company’s revenues disaggregated by revenue stream.

	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
	(In thousands)
Revenues
Oil	$	50,750	$	58,918	$	89,566	$	111,292
NGLs		6,411		13,604		14,196		27,085
Natural gas		10,232		40,356		29,915		68,373
Oil and natural gas sales	$	67,393	$	112,878	$	133,677	$	206,750

Contract Balances

Under the Company’s sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to the Company’s revenue contracts with customers was $29.7 million at June 30, 2023 and $35.1 million at December 31, 2022.

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.

13

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying Unaudited Condensed Consolidated Balance Sheets approximated fair value at June 30, 2023 and December 31, 2022. 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 June 30, 2023 and December 31, 2022 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 June 30, 2023 and December 31, 2022 for each of the fair value hierarchy levels:

	Fair Value Measurements at June 30, 2023
					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	$	—	$	6,847	$	—	$	6,847
Interest rate derivatives		—		—		—		—
Total assets	$	—	$	6,847	$	—	$	6,847
Liabilities:
Commodity derivatives	$	—	$	7,582	$	—	$	7,582
Interest rate derivatives		—		—		—		—
Total liabilities	$	—	$	7,582	$	—	$	7,582

	Fair Value Measurements at December 31, 2022
					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	$	—	$	6,257	$	—	$	6,257
Interest rate derivatives		—		—		—		—
Total assets	$	—	$	6,257	$	—	$	6,257
Liabilities:
Commodity derivatives	$	—	$	27,141	$	—	$	27,141
Interest rate derivatives		—		—		—		—
Total liabilities	$	—	$	27,141	$	—	$	27,141

See Note 5 for additional information regarding the Company’s derivative instruments.

14

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 was recorded on proved oil and natural gas properties during the three and six months ended June 30, 2023 and 2022.

Note 5. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and to achieve a more predictable cash flow in connection with natural gas and oil sales 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 the Company’s 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 the Company’s current credit agreements are counterparties to its 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. The Company has also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of its counterparties. The terms of the ISDA Agreements provide the Company and each of its counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or its 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 the Company’s Revolving Credit Facility (as defined below).

Commodity Derivatives

The Company 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. The Company recognizes all derivative instruments at fair value.

15

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company enters into natural gas derivative contracts that are indexed to NYMEX-Henry Hub. The Company also enters into oil derivative contracts indexed to NYMEX-WTI.

At June 30, 2023, the Company had the following open commodity positions:

	2023		2024
Natural Gas Derivative Contracts:
Collar contracts:
Two-way collars
Average monthly volume (MMBtu)		1,343,333		220,833
Weighted-average floor price	$	3.49	$	3.31
Weighted-average ceiling price	$	5.76	$	4.73
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (Bbls)		55,000		8,333
Weighted-average fixed price	$	57.33	$	70.00
Collar contracts:
Two-way collars
Average monthly volume (Bbls)		15,000		—
Weighted-average floor price	$	65.00	$	—
Weighted-average ceiling price	$	76.16	$	—
Three-way collars
Average monthly volume (Bbls)		50,000		—
Weighted-average ceiling price	$	74.54	$	—
Weighted-average floor price	$	58.00	$	—
Weighted-average sub-floor price	$	43.00	$	—

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 June 30, 2023 and December 31, 2022. There was no cash collateral received or pledged associated with the Company’s derivative instruments since most of its counterparties, or certain of its affiliates, to its derivative contracts are lenders under its Revolving Credit Facility.

16

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives
		June 30,		June 30,		December 31,		December 31,
Type	Balance Sheet Location	2023		2023		2022		2022
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	6,847	$	7,582	$	6,257	$	27,141
Interest rate swaps	Short-term derivative instruments		—		—		—		—
Gross fair value			6,847		7,582		6,257		27,141
Netting arrangements			(6,847)		(6,847)		(6,257)		(6,257)
Net recorded fair value	Short-term derivative instruments	$	—	$	735	$	—	$	20,884
Commodity contracts	Long-term derivative instruments	$	—	$	—	$	—	$	—
Interest rate swaps	Long-term derivative instruments		—		—		—		—
Gross fair value			—		—		—		—
Netting arrangements			—		—		—		—
Net recorded fair value	Long-term derivative instruments	$	—	$	—	$	—	$	—

Loss (Gain) on Derivative Instruments

The Company does 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 Net Income. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):

		For the Three Months Ended				For the Six Months Ended
	Statements of	June 30,				June 30,
	Operations Location	2023		2022		2023		2022
Commodity derivative contracts	Loss (gain) on commodity derivatives	$	(3,798)	$	18,571	$	(18,957)	$	111,975
(Gain) loss on interest rate derivatives	Interest expense, net		—		(286)		—		(843)

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 six months ended June 30, 2023 (in thousands):

Asset retirement obligations at beginning of period	$	116,438
Liabilities added from acquisition or drilling		5
Liabilities settled		(289)
Liabilities removed upon sale of wells		—
Accretion expense		3,917
Revision of estimates		55
Asset retirement obligation at end of period		120,126
Less: Current portion		1,499
Asset retirement obligations - long-term portion	$	118,627

17

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 7. Long-Term Debt

The following table presents the Company’s consolidated debt obligations at the dates indicated:

	June 30,		December 31,
	2023		2022
	(In thousands)
Revolving Credit Facility (1)	$	120,000	$	190,000
Total long-term debt	$	120,000	$	190,000

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

Revolving Credit Facility

OLLC, the Company’s wholly owned subsidiary, was a party to a reserve-based revolving credit facility (the “Revolving Credit Facility”), subject to a borrowing base of $180.0 million as of June 30, 2023, which was guaranteed by the Company and all of its current subsidiaries. The Revolving Credit Facility would have matured on May 31, 2024. The Company’s borrowing base under its Revolving Credit Facility was subject to redetermination on at least a semi-annual basis, primarily based on a reserve engineering report.

As of June 30, 2023, the Company was in compliance with all the financial (current ratio and total leverage ratio) and non-financial covenants associated with its Revolving Credit Facility.

Amended and Restated Credit Agreement

Subsequent Events. On July 31, 2023, OLLC and Amplify Acquisitionco LLC (“Acquisitionco”), as the direct parent of OLLC and wholly owned subsidiary of the Company, amended and restated the Revolving Credit Facility with Keybanc Capital Markets Inc., Cadence Bank, N.A. and Citizens Bank, N.A. as joint lead arrangers and KeyBank National Association as the administrative agent (the “New Credit Facility”). The New Credit Facility is a replacement in full of the Revolving Credit Facility.

The aggregate principal amount of loans outstanding under the New Credit Facility as of July 31, 2023, was $120.0 million. The initial borrowing base under the facility is $150.0 million with elected commitments of $135.0 million, and, consistent with the prior Revolving Credit Facility, the New Credit Facility borrowing base will be redetermined on a semi-annual basis with the next redetermination expected to occur in the fourth quarter of 2023.

Certain key terms and conditions under the New Credit Facility include (but are not limited to):

● A maturity date of July 31, 2027;

● The loans shall bear interest at a rate per annum equal to (i) adjusted SOFR or (ii) an adjusted base rate, plus an applicable margin based on a utilization ratio of the lesser of the borrowing base and the aggregate commitments. The applicable margin ranges from 2.00% to 3.00% for adjusted base rate borrowings, and 3.00% to 4.00% for adjusted SOFR borrowings;

● The unused commitments under the New Credit Facility will accrue a commitment fee of 0.50%, payable quarterly in arrears;

● Certain financial covenants, including the maintenance of (i) a net debt leverage ratio not to exceed 3.00 to 1.00, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending and (ii) a current ratio of not less than 1.00 to 1.00, determined as of the last day of each fiscal quarter, in each case commencing with the fiscal quarter ending December 31, 2023;

18

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

● Certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy; and

● Initial minimum hedging requirements covering 75% of the reasonably projected monthly production of hydrocarbons from proved developed producing reserves for the 24-month period following the effective date of the New Credit Facility (the “First Period”) and (ii) 50% for the 12-month period immediately following the First Period.

Weighted-Average Interest Rates

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

	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
Revolving Credit Facility	8.67	%	4.54	%	9.31	%	4.16	%

Letters of Credit

At June 30, 2023, the Company had no letters of credit outstanding.

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with the Company’s Revolving Credit Facility was $0.8 million at June 30, 2023. For the six months ended June 30, 2023, the Company wrote-off $0.3 million of deferred financing costs in connection with the decrease in the Company’s borrowing base.

Note 8. Equity

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 the Company’s common stock issued for the six months ended June 30, 2023:

	Common Stock
Balance, December 31, 2022	38,459,731
Issuance of common stock	—
Restricted stock units vested	749,770
Shares withheld for taxes (1)	(238,075)
Balance, June 30, 2023	38,971,426

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

19

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
Net income (loss)	$	9,816	$	29,220	$	362,575	$	(19,394)
Less: Net income allocated to participating securities		433		1,402		16,422		—
Basic and diluted earnings available to common stockholders	$	9,383	$	27,818	$	346,153	$	(19,394)
Common shares:
Common shares outstanding — basic		38,971		38,330		38,833		38,256
Dilutive effect of potential common shares		—		—		—		—
Common shares outstanding — diluted		38,971		38,330		38,833		38,256
Net earnings (loss) per share:
Basic	$	0.24	$	0.73	$	8.91	$	(0.51)
Diluted	$	0.24	$	0.73	$	8.91	$	(0.51)

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”) was replaced by the EIP and no further awards will be allowed to be granted under the Legacy Amplify MIP. As of June 30, 2023, an aggregate of 932,675 shares were available for future grants under the EIP.

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 $6.0 million at June 30, 2023. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.2 years.

20

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

		Weighted-
		Average Grant-
	Number of	Date Fair Value
	Units	per Unit (1)
TSUs outstanding at December 31, 2022	1,502,556	$	3.82
Granted (2)	569,135	$	8.44
Forfeited	(59,679)	$	6.22
Vested	(595,090)	$	3.57
TSUs outstanding at June 30, 2023	1,416,922	$	5.68

(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 six months ended June 30, 2023 was $4.8 million based on a grant-date market price ranging from $6.52 to $8.91 per share.

Restricted Stock Units with Market and Service Vesting Conditions

The restricted stock units with market and service vesting conditions (“PSUs” or “PRSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. The fair value of the awards is estimated on their grant dates using a Monte Carlo simulation. The Company recognizes compensation cost over the requisite service or performance period. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with these awards was $2.9 million at June 30, 2023. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.5 years.

2020 PSU Awards

The 2020 PSU awards vested based on the satisfaction of service and market vesting conditions, and the market vesting was based on the Company’s achievement of certain share price targets. The PSUs were subject to service-based vesting such that 50% of the PSUs service vested on the applicable market vesting date and an additional 25% of the PSUs service vested on each of the first and second anniversaries of the applicable market vesting date.

2021 PRSU Awards

The 2021 PRSU awards were issued collectively in separate tranches with individual performances periods beginning on January 1, 2021. 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 performance period of January 1, 2021 through December 31, 2021; 25% able to vest during the period January 1, 2021 through December 31, 2022 and 50% able to vest during the period of January 1, 2021 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 applicable performance period.

2022 and 2023 PRSU Awards

The 2022 and 2023 PRSU awards were issued with a three-year vesting period beginning on the grant date and ending on the third anniversary of the grant date. The three-year performance period for the 2022 awards is January 1, 2022 through December 31, 2024. The three-year performance period for the 2023 awards is January 1, 2023 through December 31, 2025. 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 applicable performance period.

21

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The below table reflects the ranges for the assumptions used in the Monte Carlo model for the 2023 PRSUs awards:

	February 2023		April 2023
Expected volatility	119.2	%	92.5	%
Dividend yield	0.00	%	0.00	%
Risk-free interest rate	3.74	%	3.78	%

The following table summarizes information regarding the PSUs and PRSUs granted under the EIP for the period presented:

		Weighted-
		Average Grant-
	Number of	Date Fair Value
	Units	per Unit (1)
PSUs and PRSUs outstanding at December 31, 2022	380,512	$	4.28
Granted (2)	321,436	$	10.59
Forfeited	(144,567)	$	6.55
Vested	(154,680)	$	2.20
PSUs and PRSUs outstanding at June 30, 2023	402,701	$	9.31

(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 six months ended June 30, 2023 was $3.4 million based on a calculated fair value price ranging from $1.27 to $15.04 per share.

Compensation Expense

The following table summarizes the amount of recognized compensation expense associated with the EIP, which are reflected in the accompanying Unaudited Condensed Consolidated Statements of Net Income for the periods presented (in thousands):

	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
Equity classified awards
TSUs		1,040		690		1,938		1,281
PSUs and PRSUs		300		164		343		217
Board RSUs		—		1		—		5
	$	1,340	$	855	$	2,281	$	1,503

Note 11. Leases

The Company has leases for office space and equipment in its corporate office and operating regions as well as warehouse space, vehicles, compressors and surface rentals related to its business operations. In addition, the Company has offshore Southern California pipeline right-of-way use agreements. Most of the Company’s leases, other than its 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 the Company’s leases can be terminated with 30-day prior written notice. The majority of its month-to-month leases are not included as a lease liability in its balance sheet 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. For the quarter ended June 30, 2023, all of the Company’s leases qualified as operating leases and it did not have any existing or new leases qualifying as financing leases or variable leases.

22

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company’s corporate office lease does not provide an implicit rate. To determine the present value of the lease payments, the Company uses its incremental borrowing rate based on the information available at the inception date. To determine the incremental borrowing rate, the Company applies a portfolio approach based on the applicable lease terms and the current economic environment. The Company uses a reasonable market interest rate for its office equipment and vehicle leases.

For the six months ended June 30, 2023 and 2022, the Company recognized approximately $1.1 million and $0.7 million, respectively, of costs relating to the operating leases in the Unaudited Condensed Consolidated Statements of Net Income.

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

	For the Six Months Ended
	June 30,
	2023		2022
	(In thousands)
Non-cash amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	948	$	3,874

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

	June 30,		December 31,
	2023		2022
	(In thousands)
Right-of-use asset	$	6,428	$	7,376
Lease liabilities:
Current lease liability		1,462		1,401
Long-term lease liability		5,818		6,567
Total lease liability	$	7,280	$	7,968

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
2023	$	685	$	478	$	1,163
2024		1,369		670		2,039
2025		1,369		484		1,853
2026		1,151		5		1,156
2027 and thereafter		2,466		—		2,466
Total lease payments		7,040		1,637		8,677
Less: interest		1,270		127		1,397
Present value of lease liabilities	$	5,770	$	1,510	$	7,280

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AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	June 30,
	2023		2022
Weighted average remaining lease term (years):
Office and warehouse space	4.46		5.92
Vehicles	0.35		0.10
Office equipment	0.03		0.06
Weighted average discount rate:
Office leases	5.01	%	5.60	%
Vehicles	1.27	%	0.16	%
Office equipment	0.10	%	0.15	%

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):

	June 30,		December 31,
	2023		2022
Accrued liability - pipeline incident	$	14,936	$	20,832
Accrued lease operating expense		11,155		11,226
Accrued current income taxes		5,684		—
Accrued liability - current portion of pipeline incident settlement		4,888		4,888
Accrued capital expenditures		4,527		2,714
Accrued general and administrative expense		4,216		4,943
Accrued production and ad valorem tax		3,978		4,675
Accrued commitment fee and other expense		2,990		5,824
Operating lease liability		1,462		1,401
Asset retirement obligations		1,499		1,824
Other		52		122
Accrued liabilities	$	55,387	$	58,449

Accounts Receivable

Accounts receivable consisted of the following at the dates indicated (in thousands):

	June 30,		December 31,
	2023		2022
Oil and natural gas receivables	$	29,724	$	35,083
Insurance receivable - pipeline incident		30,418		41,961
Joint interest owners and other		4,515		5,047
Total accounts receivable		64,657		82,091
Less: allowance for doubtful accounts		(1,636)		(1,636)
Total accounts receivable, net	$	63,021	$	80,455

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AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flows

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

	For the Six Months Ended
	June 30,
	2023		2022
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	7,155	$	4,502
Cash paid for taxes		5,050		35
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		3,294		7,605

Note 13. Related Party Transactions

Related Party Agreements

There have been no transactions between the Company and any related person in which the related person had a direct or indirect material interest for the three and six months ended June 30, 2023 and 2022.

Note 14. Commitments and Contingencies

Litigation and Environmental

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters.

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

At June 30, 2023 and December 31, 2022, the Company had no environmental reserves recorded in its Unaudited Condensed Consolidated Balance Sheet.

Southern California Pipeline Incident

On August 25, 2022, the Company reached an agreement in principle with plaintiffs in a putative class action pending in the United States District Court for the Central District of California to resolve all civil claims against the Company and its subsidiaries related to the Incident. The settlement of $50.0 million, which also includes certain injunctive relief, will be funded under the Company’s insurance policies. The Court preliminarily approved the settlement on December 7, 2022 and granted final approval on April 24, 2023.

On August 26, 2022, the Company reached an agreement with the United States government, which the court has approved, to resolve all federal criminal matters involving the Company and its subsidiaries stemming from Incident. As part of the resolution with the United States, the Company agreed to plead guilty to one count of misdemeanor negligent discharge of oil in violation of the Clean Water Act. The Company will pay a fine of approximately $7.1 million in installments over a period of three years, serve a term of four years’ probation and reimburse governmental agencies approximately $5.8 million for their response to this event. The Company also has agreed to implement certain compliance measures including installation of a new leak detection system and increased Remote Operated Vehicle inspections of the pipeline. As of June 30, 2023, the Company recorded $2.0 million in “Accrued liability – pipeline incident” and $3.1 million in “Other long-term liabilities” for the remaining payments related to this settlement on its Unaudited Condensed Consolidated Balance Sheet.

25

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On September 8, 2022, the Company reached an agreement with the state of California to resolve all related state criminal matters. As part of the resolution with the state of California, which also has court approval, the Company agreed to enter a plea of No Contest to six misdemeanor charges. The Company will pay a fine in the amount of $4.9 million to be distributed among the state of California, including the State’s Fish and Game Preservation Fund, and Orange County. The Company also will serve a one-year term of probation and has agreed to certain compliance enhancements to its operations. As of June 30, 2023, the Company recorded $2.9 million in “Accrued liability − pipeline incident” for the remaining payments related to this settlement on its Unaudited Condensed Consolidated Balance Sheet.

On March 1, 2023, the Company announced that the vessels that struck and damaged the pipeline and their respective owners and operators agreed to pay the Company $96.5 million in a settlement. The Marine Exchange of Los Angeles-Long Beach Harbor (the “Marine Exchange”) agreed to non-monetary terms as well. The overall resolution included subrogation claims by Amplify’s property damage and loss of production income (“LOPI”) insurers, with Amplify ultimately receiving a net payment of approximately $85.0 million. The settlement resolved Amplify’s affirmative claims related to the Incident. As part of the settlement, Amplify dismissed its legal claims against those parties.

The Company is also participating in a related claims process organized under the Oil Pollution Act of 1990, 33 U.S.C. § 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 ongoing.

Future litigation may be necessary, among other things, to defend the Company 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 the Company because of defense and settlement costs, diversion of management resources, and other factors.

For further information regarding the Incident, please see Note 16.

Minimum Volume Commitment

The Company was party to a gas purchase, gathering and processing contract in Oklahoma, which included certain minimum NGL commitments. To the extent the Company did not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, it was required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The commitment fee expense for the six months ended June 30, 2023 and 2022 was approximately $0.3 million and $1.1 million, respectively. The minimum volume commitment for Oklahoma ended on June 30, 2023.

Sinking Fund Trust Agreement

Beta Operating Company, LLC (“Beta”), a wholly owned subsidiary, assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Company properties in federal waters offshore Southern California, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay Pipeline that lies within state waters and the surface facilities. Under the terms of the agreement, the operator of the properties is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of June 30, 2023, the account balance included in restricted investments was approximately $4.4 million.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

Beta has a decommissioning obligation with BOEM in connection with its 2009 acquisition of the Company’s properties in federal waters offshore Southern California. The Company supports its decommissioning obligation with $161.3 million of A-rated surety bonds.

26

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In December 2021, the Company entered into two escrow funding agreements with its surety providers to fund interest-bearing escrow accounts on a quarterly basis to reimburse and indemnify the surety providers for any claims arising under the surety bonds related to the decommissioning of our Beta properties. The obligation ceases when the aggregate value of the escrow accounts reaches $172.6 million. As of June 30, 2023, the Company has funded $11.2 million into the escrow accounts which is reflected in “Restricted investments” on the Unaudited Condensed Consolidated Balance Sheet.

Note 15. Income Taxes

Net deferred tax assets relate to net operating loss carryforwards, interest expense carryforwards, tax credits, and other temporary differences expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific federal and state tax jurisdictions in which those temporary differences are deductible. In assessing the need for a valuation allowance on its deferred tax assets, the Company considers whether it is more likely than not that some portion of or all its deferred tax assets will not be realized. On December 31, 2022, the Company valuation allowance was $284.9 million, which offset all net deferred tax assets as of such date.

As of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. The assessment considers all available information including historical and forecasted taxable income and operating history. The three months ended March 31, 2023 marked the first time that the Company had achieved three years of cumulative income. Furthermore, management determined that the Company’s ability to maintain long-term profitability despite near-term changes in commodity prices and capital and operating costs demonstrated that there is sufficient positive evidence to conclude that it is more likely than not that all net deferred tax asset is realizable. As a result of the Company’s assessment, the Company released substantially all of its valuation allowance previously recorded. The result of the valuation allowance release for the six months ended June 30, 2023 was a tax benefit of $279.3 million.

The Company’s current income tax benefit (expense) was $6.9 million and ($5.7) million for the three and six months ended June 30, 2023, respectively. No current income tax expense was recorded for the three and six months ended June 30, 2022. The Company’s deferred income tax benefit (expense) was less than ($0.1) million and $259.4 million for the three and six months ended June 30, 2023, respectively. No deferred income tax benefit was recorded for the three and six months ended June 30, 2022. The effective tax rates for the three and six months ended June 30, 2023 were (226.0%) and (233.2%), respectively. The effective tax rate was 0% for the three and six months ended June 30, 2022. The item that had the most significant impact on the difference between the statutory U.S. federal income tax rate of 21% and the effective tax rate for the three and six months ended June 30, 2023 was the release of the valuation allowance. The items that had the most significant impact on the difference between the statutory U.S. federal income tax rate of 21% and the effective tax rate for the three and six months ended June 30, 2022, was primarily due to our recorded valuation allowances.

Note 16. Southern California Pipeline Incident

On October 2, 2021, contractors operating under the direction of Beta Operating Company, LLC, a subsidiary of the Company, 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 (the “BSEE”) 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.

27

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 was 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” and its owner Dordellas Finance Corporation and operator Mediterranean Shipping Company, S.A. as parties in interest in connection with an anchor-dragging incident, in January 2021 (the “Anchor Dragging Incident”), which occurred in close proximity to the Company’s pipeline, and that additional vessels of interest continued to be investigated. On November 19, 2021, the U.S. Coast Guard announced that it had identified the COSCO (Beijing) as another vessel involved in the Anchor Dragging Incident and named its owner Capetanissa Maritime Corporation of Liberia and its operator V.Ships Greece Ltd. as parties in interest. The cause, timing and details regarding the Incident remain under investigation.

At the height of the Incident response, the Company deployed 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 February 2, 2022, the Unified Command announced that response and monitoring efforts have officially concluded for the Incident, and Unified Command would stand down as of such date. Amplify is grateful to its Unified Command partners for their collaboration and professionalism over the course of the response.

In response to the Incident, all operations were suspended and the pipeline was shut-in pending the Company’s receipt of the required regulatory approvals to restart operations. On October 4, 2021, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), Office of Pipeline Safety issued a Corrective Action Order 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. On April 10, 2023, the Company announced that it has received the required approvals from federal regulatory agencies to restart operations at the Beta Field. The pipeline will be operated in accordance with the restart procedures that were reviewed and approved by PHMSA.

On December 15, 2021, a federal grand jury in the Central District of California returned a federal criminal indictment against Amplify Energy Corp., Beta Operating Company, LLC, and San Pedro Bay Pipeline Company in connection with the Incident. The indictment alleges that the Company committed a misdemeanor violation of the federal Clean Water Act for negligently discharging oil into the contiguous zone of the United States. As previously disclosed, state authorities were conducting parallel criminal investigations. The Company has reached court-approved agreements to resolve all criminal matters stemming from the Incident. Specifically, on August 26, 2022, as part of the resolution with the United States, the Company agreed to plead guilty to one count of misdemeanor negligent discharge of oil in violation of the Clean Water Act. The Company will pay a fine of approximately $7.1 million in installments over a period of three years, serve a term of four years’ probation and reimburse governmental agencies approximately $5.8 million for their response to this event. Further, on September 8, 2022, as part of the resolution with the state of California, the Company agreed to enter a plea of No Contest to six misdemeanor charges. The Company will pay a fine in the amount of $4.9 million to be distributed among the state of California, including the State’s Fish and Game Preservation Fund, and Orange County. The Company will serve a one-year term of probation and has agreed to certain compliance enhancements to its operations.

28

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company is currently subject to a number of ongoing investigations related to the Incident by certain federal and state agencies. To date, the U.S. Coast Guard, the U.S. Bureau of Ocean Energy Management, the U.S. Department of Justice, PHMSA, the U.S. Department of the Interior Bureau of Safety and Environmental Enforcement, the National Transportation Safety Board, the California Department of Justice, the Orange County District Attorney, the Los Angeles County District Attorney, and the California Department of Fish & Wildlife have conducted or are conducting investigations or examinations of the Incident. On April 8, 2022, in light of the allegations raised in the December 15, 2021 federal indictment, the Company received a Show Cause Notice from the EPA asking the Company to provide information as to why it should not be suspended from participating in future federal contracting pursuant to 2 C.F.R. § 180.700(a), (c) and 2 C.F.R. § 180.800(a)(4). On April 22, 2022, the Company responded to the Show Cause Notice. On September 9, 2022, the EPA informed the Company’s counsel that the EPA has administratively closed the case at this time, and as such, the Company is no longer under a Show Cause Notice. On April 6, 2023, PHMSA provided the Company notice of PHMSA’s positions regarding “probable violations of the Pipeline Safety Regulations” in connection with the Incident; the Company has responded to that notice with the Company’s positions and is conferring with PHMSA regarding a resolution. Other federal agencies may or have commenced investigations and proceedings, and may initiate enforcement actions seeking penalties and other relief under the Clean Water Act and other statutes. Amplify continues to comply with all regulatory requirements and investigations. 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 liability.

The Company, Beta Operating Company, LLC, and San Pedro Bay Pipeline Company were named as defendants in a consolidated putative class action in the United States District Court for the Central District of California. Plaintiffs filed a consolidated class action complaint on January 28, 2022 and an amended complaint on March 21, 2022. Plaintiffs asserted claims against the Company, Beta Operating Company, LLC, San Pedro Bay Pipeline Company, MSC Mediterranean Shipping Company, Dordellas Finance Corp., the MSC Danit (proceeding in rem), Costamare Shipping Co. S.A., Capetanissa Maritime Corporation of Liberia, V.Ships Greece Ltd., and the COSCO Beijing (proceeding in rem). The Company filed a third-party complaint on February 28, 2022, an amended complaint on June 21, 2022, and second amended complaint on October 5, 2022. The Company sued the same shipping defendants as had Plaintiffs and added claims against the Marine Exchange, COSCO Shipping Lines Co. Ltd., COSCO (Cayman) Mercury Co. Ltd., Mediterranean Shipping Company S.r.l., and MSC Shipmanagement Limited.

MSC Mediterranean Shipping Company, Dordellas Finance Corp., and Capetanissa Maritime Corporation of Liberia also filed petitions for limitations of liability under maritime law in the United States District Court for the Central District of California. The court consolidated the limitation actions into a single limitation action and also coordinated discovery between the consolidated limitation and the consolidated class actions. On April 17, 2023, the Court stayed the Limitation Action pending the documentation and approval of certain settlements that are expected to fully resolve the Limitation Action.

On August 25, 2022, the Company reached an agreement in principle with plaintiffs in the class action to resolve all civil claims against it and its subsidiaries. The settlement of $50.0 million, which also includes certain injunctive relief, will be funded under the Company’s insurance policies. The Court preliminarily approved the settlement on December 7, 2022 and granted final approval on April 24, 2023.

On March 1, 2023, the Company announced that the vessels that struck and damaged the pipeline and their respective owners and operators agreed to pay the Company $96.5 million in a settlement. The Marine Exchange agreed to non-monetary terms as well. The overall resolution included subrogation claims by Amplify’s property damage and LOPI insures, with Amplify ultimately receiving a net payment of approximately $85.0 million. The settlement resolved Amplify’s affirmative claims related to the Incident. As part of the settlement, Amplify dismissed its legal claims against those parties.

29

AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Under the OPA 90, the Company’s pipeline was designated by the U.S. 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. In addition, the Natural Resource Damage Assessment remains ongoing and therefore the extent, timing and cost related to such assessment are difficult to project. While the Company anticipates insurance will reimburse it for expenses related to the Natural Resource Damage Assessment, any potentially uncovered expenses may be material and could impact the Company’s business and results of operations and could put pressure on its liquidity position going forward.

Based on presently enacted laws and regulations and currently available facts, the Company estimates that the total costs it has incurred or will incur with respect to the Incident to be approximately $190.0 million to $210.0 million, which includes (i) actual and projected response and remediation under the direction of the Unified Command, (ii) estimated fines and penalties of $12.0 million resulting from the resolution of the federal and state of California matters discussed above, and (iii) certain legal fees.

The range of total costs is based on the Company’s assumptions regarding (i) settlement of costs associated with certain vendors for response and remediation expenses, (ii) resolution of certain third-party claims, excluding claims with respect to losses, which are not probable or reasonably estimable, and (iii) future claims and lawsuits. While the Company believes it has accurately reflected all probable and reasonably estimable costs incurred in the Company’s Unaudited Consolidated Statements of Net Income, these estimates are subject to uncertainties associated with the underlying assumptions. For example, settlements with vendors for response and remediation expenses may be significantly higher or lower than the Company has currently estimated. Accordingly, as the Company’s assumptions and estimates may change in future periods based on future events, the Company can provide no assurance that total costs will not materially change in future periods.

The Company’s estimates do not include (i) the nature, extent and cost of future legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Incident, (ii) any lost revenue associated with the suspension of operations at Beta, (iii) any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where the Company currently regards the likelihood of loss as being only reasonably possible or remote and (iv) the costs associated with the permanent repair of the pipeline and the restart of operations at Beta.

In accordance with customary insurance practice, the Company maintains insurance policies, including LOPI insurance, against many potential losses or liabilities arising from its 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 its operations and is subject to certain exclusions and deductibles. While the Company expects its insurance policies will cover a material portion of the total aggregate costs associated with the Incident, including but not limited to response and remediation expenses, defense costs and loss of revenue resulting from suspended operations, it 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.

On June 30, 2023, and December 31, 2022, the Company’s insurance receivables were $30.4 million and $42.0 million, respectively. Excluding the costs associated with the resolution of the federal and state matters discussed above, for the six months ended June 30, 2023, the Company incurred response and remediation expenses and legal fees of $29.5 million. Of these costs, the Company has received, or expects that it is probable that it will receive, $14.4 million in insurance recoveries. The remaining amount of $15.1 million, which primarily relates to certain legal costs that are not expected to be recovered under an insurance policy, are classified as “Pipeline Incident Loss” on the Company’s Unaudited Condensed Consolidated Statements of Net Income. For the six months ended June 30, 2023, the Company received $26.0 million in insurance recoveries.

Additionally, during the six months ended June 30, 2023, the Company recognized $17.9 million related to approved LOPI insurance proceeds, which is classified as “Other Revenues” in the Company’s Unaudited Condensed Consolidated Statements of Net Income.

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AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 17. Subsequent Events

Amended and Restated Credit Agreement

See Note 7 for additional information relating to the Company’s refinancing of its Revolving Credit Facility.

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, 2022 (“2022 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. Our 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

Oil, natural gas and NGLs prices have decreased in 2023 when compared to the same period of 2022 and, as a result, we experienced a decrease in revenues. We continue to monitor the impact of the actions of the Organization of the Petroleum Exporting Countries and other large producing nations, the Russia-Ukraine conflict, global inventories of oil and gas and the uncertainty associated with recovering oil demand, inflation and future monetary policy, and governmental policies aimed at transitioning towards lower carbon energy. We expect prices for some or all of the commodities to remain volatile. The COVID-19 pandemic and the Russia-Ukraine conflict continue to evolve, and the extent to which these events may impact our business, results of operations, financial condition and cash flows will depend on future developments, which are highly uncertain and cannot be predicted with confidence.

Recent Developments

Amended and Restated Credit Agreement

On July 31, 2023, OLLC and Acquisitionco amended and restated the Revolving Credit Facility with Keybanc Capital Markets Inc., Cadence Bank, N.A. and Citizens Bank, N.A. as joint lead arrangers and KeyBank National Association as the administrative agent (the “New Credit Facility”). The New Credit Facility is a replacement in full of the Revolving Credit Facility.

The aggregate principal amount of loans outstanding under the New Credit Facility as of July 31, 2023, was $120.0 million. The initial borrowing base under the facility is $150.0 million with elected commitments of $135.0 million, and, consistent with our prior Revolving Credit Facility, the New Credit Facility borrowing base will be redetermined on a semi-annual basis with the next redetermination expected to occur in the fourth quarter of 2023.

Certain key terms and conditions under the New Credit Facility include (but are not limited to):

● A maturity date of July 31, 2027;

● The loans shall bear interest at a rate per annum equal to (i) adjusted SOFR or (ii) an adjusted base rate, plus an applicable margin based on a utilization ratio of the lesser of the borrowing base and the aggregate commitments. The applicable margin ranges from 2.00% to 3.00% for adjusted base rate borrowings, and 3.00% to 4.00% for adjusted SOFR borrowings;

32

● The unused commitments under the New Credit Facility will accrue a commitment fee of 0.50%, payable quarterly in arrears;

● Certain financial covenants, including the maintenance of (i) a net debt leverage ratio not to exceed 3.00 to 1.00, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending and (ii) a current ratio of not less than 1.00 to 1.00, determined as of the last day of each fiscal quarter, in each case commencing with the fiscal quarter ending December 31, 2023;

● Certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy; and

● Initial minimum hedging requirements covering 75% of the reasonably monthly production of hydrocarbons from proved developed producing reserves for the 24-month period following the effective date of the New Credit Facility (the “First Period”) and (ii) 50% for the 12-month period immediately following the First Period.

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 is 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.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates, including a discussion regarding the estimation uncertainty and the impact that our critical accounting estimates have had, or are reasonably likely to have, on our financial condition or results of operations, are described in Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2022 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; fair value estimates; revenue recognition; and contingencies and insurance accounting. 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 six months ended June 30, 2023 and 2022 have been derived from our unaudited condensed consolidated financial statements. The comparability of the results of operations among the periods presented below is impacted by the Incident and suspension of operations at our Beta properties.

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

	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
	($ In thousands except per unit amounts)
Oil and natural gas sales	$	67,393	$	112,878	$	133,677	$	206,750
Other revenues		4,578		8,899		18,164		26,460
Lease operating expense		34,903		33,285		67,863		66,205
Gathering, processing and transportation		5,149		7,281		10,751		15,291
Taxes other than income		5,205		8,623		10,498		16,176
Depreciation, depletion and amortization		7,072		5,864		12,880		11,499
General and administrative expense		7,778		8,628		16,292		16,399
Loss (gain) on commodity derivative instruments		(3,798)		18,571		(18,957)		111,975
Pipeline incident loss		6,844		5,092		15,123		5,672
Interest expense, net		3,701		3,084		9,438		5,525
Litigation settlement		—		—		84,875		—
Income tax (expense) benefit - current		6,853		—		(5,674)		—
Income tax (expense) benefit - deferred		(48)		—		259,422		—
Net income (loss)		9,816		29,220		362,575		(19,394)
Oil and natural gas revenues:
Oil sales	$	50,750	$	58,918	$	89,566	$	111,292
NGL sales		6,411		13,604		14,196		27,085
Natural gas sales		10,232		40,356		29,915		68,373
Total oil and natural gas revenues	$	67,393	$	112,878	$	133,677	$	206,750
Production volumes:
Oil (MBbls)		727		557		1,262		1,137
NGLs (MBbls)		324		347		650		685
Natural gas (MMcf)		5,263		5,725		10,567		11,235
Total (MBoe)		1,928		1,858		3,672		3,695
Average net production (MBoe/d)		21.2		20.4		20.3		20.4
Average realized sales price (excluding commodity derivatives):
Oil (per Bbl)	$	69.86	$	105.79	$	70.99	$	97.84
NGL (per Bbl)		19.80		39.18		21.86		39.51
Natural gas (per Mcf)		1.94		7.05		2.83		6.09
Total (per Boe)	$	34.97	$	60.74	$	36.40	$	55.95
Average unit costs per Boe:
Lease operating expense	$	18.10	$	17.91	$	18.48	$	17.92
Gathering, processing and transportation		2.67		3.92		2.93		4.14
Taxes other than income		2.70		4.64		2.86		4.38
General and administrative expense		4.03		4.64		4.44		4.44
Depletion, depreciation and amortization		3.67		3.16		3.51		3.11

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For the Three Months Ended June 30, 2023 Compared to the Three Months Ended June 30, 2022

Net income of $9.8 million and $29.2 million were recorded for the three months ended June 30, 2023 and 2022, respectively.

Oil, natural gas and NGL revenues were $67.4 million and $112.9 million for the three months ended June 30, 2023 and 2022, respectively. Average net production volumes were approximately 21.2 MBoe/d and 20.4 MBoe/d for the three months ended June 30, 2023 and 2022, respectively. The change in production volumes was primarily due to the restart of operations at Beta and was partially offset by natural declines. The average realized sales price was $34.97 per Boe and $60.74 per Boe for the three months ended June 30, 2023 and 2022, respectively. The decrease in average realized sales price was primarily due to the decrease in commodity prices.

Other revenues were $4.6 million and $8.9 million for the three months ended June 30, 2023 and 2022, respectively. The change in other revenues was primarily related to one month of loss of production income (“LOPI”) insurance proceeds of $4.5 million for the three months ended June 30, 2023 compared to two months of LOPI proceeds of $8.8 million for the three months ended June 30, 2022.

Lease operating expense was $34.9 million and $33.3 million for the three months ended June 30, 2023 and 2022, respectively. On a per Boe basis, lease operating expense was $18.10 and $17.91 for the three months ended June 30, 2023 and 2022, respectively. The change in lease operating expense on a per Boe basis was due to higher costs associated with the restart of operations at Beta.

Gathering, processing and transportation expense was $5.1 million and $7.3 million for the three months ended June 30, 2023 and 2022, respectively. The decrease in gathering, processing and transportation expense was primarily related to the expiration of the minimum volume commitment (“MVC”) fee for the East Texas/North Louisiana property in November 2022. During the three months ended June 30, 2022, we started marketing our own natural gas in Oklahoma, which resulted in us now recognizing certain revenue deductions as gathering, processing and transportation expenses. On a per Boe basis, gathering, processing and transportation expense was $2.67 and $3.92 for the three months ended June 30, 2023 and 2022, respectively. The change on a per BOE basis is primarily related to decrease in production and a decrease in MVC fees.

Taxes other than income were $5.2 million and $8.6 million for the three months ended June 30, 2023 and 2022, respectively. The decrease was due to a reduction in production taxes as a result of lower commodity prices and lower production. On a per Boe basis, taxes other than income were $2.70 and $4.64 for the three months ended June 30, 2023 and 2022, respectively.

DD&A expense was $7.1 million and $5.9 million for the three months ended June 30, 2023 and 2022, respectively. The change in DD&A expense was primarily due to an increase in production of 70 MBoe, which equates to an increase of approximately $0.2 million in the change of production and an increase of $1.0 million in our depletion rate.

General and administrative expense was $7.8 million and $8.6 million for the three months ended June 30, 2023 and 2022, respectively. The change in general and administrative expense was primarily related to (i) a decrease of $0.8 million in legal expense, and (ii) a decrease of $0.6 million in professional services partially offset by (i) an increase of $0.5 million in stock compensation expense and (ii) an increase of $0.1 million in salaries and other payroll benefits.

Net gain on commodity derivative instruments of $3.8 million were recognized for the three months ended June 30, 2023, consisting of a $1.5 million of cash settlements received on expired positions and an increase of $2.3 million in the fair value of open positions. Net loss on commodity derivative instruments of $18.6 million was recognized for the three months ended June 30, 2022, consisting of a $30.0 million increase in the fair value of open positions offset by $48.6 million of cash settlements paid on expired positions.

Pipeline incident loss was $6.8 million and $5.1 million for the three months ended June 30, 2023 and 2022, respectively. The costs reflect certain expenses that are not expected to be recovered under an insurance policy. See Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Litigation settlement was not recorded for the three months ended June 30, 2023 and 2022.

Interest expense, net was $3.7 million and $3.1 million for the three months ended June 30, 2023 and 2022, respectively. The change in interest expense is primarily due to higher interest rates offset by lower debt outstanding during the period.

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Average outstanding borrowings under our Revolving Credit Facility were $123.8 million and $219.4 million for the three months ended June 30, 2023 and 2022, respectively.

Current income tax benefit (expense) was $6.9 million for the three months ended June 30, 2023. See additional information discussed in Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. No current income tax expense was recorded for the three months ended June 30, 2022.

Deferred income tax benefit (expense) was less than ($0.1) million for the three months ended June 30, 2023. Starting in the first quarter of 2023, we achieved three years of cumulative income which allowed the release of the valuation allowance. See additional information discussed in Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. No deferred income tax benefit was recorded for the three months ended June 30, 2022.

For the Six Months Ended June 30, 2023 Compared to the Six Months Ended June 30, 2022

Net income of $362.6 million and a net loss of $19.4 million were recorded for the six months ended June 30, 2023 and 2022, respectively.

Oil, natural gas and NGL revenues were $133.7 million and $206.8 million for the six months ended June 30, 2023 and 2022, respectively. Average net production volumes were approximately 20.3 MBoe/d and 20.4 MBoe/d for the six months ended June 30, 2023 and 2022, respectively. The change in production volumes was primarily due to the restart of operations at Beta and natural declines. The average realized sales price was $36.40 per Boe and $55.95 per Boe for the six months ended June 30, 2023 and 2022, respectively. The decrease in average realized sales price was primarily due to the decrease in commodity prices.

Other revenues were $18.2 million and $26.5 million for the six months ended June 30, 2023 and 2022, respectively. The change in other revenues was primarily related to LOPI insurance proceeds of $17.9 million for the six months ended June 30. 2023 compared to $26.2 million of LOPI proceeds for the six months ended June 30, 2022.

Lease operating expense was $67.9 million and $66.2 million for the six months ended June 30, 2023 and 2022, respectively. On a per Boe basis, lease operating expense was $18.48 and $17.92 for the six months ended June 30, 2023 and 2022, respectively. The change in lease operating expense on a per Boe basis was due to higher costs associated with the restart of operations at Beta partially offset with lower production.

Gathering, processing and transportation expense was $10.8 million and $15.3 million for the six months ended June 30, 2023 and 2022, respectively. The decrease in gathering, processing and transportation expense was primarily related to the expiration of the MVC fee for the East Texas/North Louisiana property in November 2022. During the six months ended June 30, 2022, we started marketing our own natural gas in Oklahoma, which improved our differentials, but, in 2022, we started to recognize certain revenue deductions as gathering, processing and transportation expenses. On a per Boe basis, gathering, processing and transportation expense was $2.93 and $4.14 for the six months ended June 30, 2023 and 2022, respectively. The change on a per BOE basis primarily related to decrease in production and a decrease in MVC fees.

Taxes other than income were $10.5 million and $16.2 million for the six months ended June 30, 2023 and 2022, respectively. The decrease was due to a reduction in production taxes as a result of lower commodity prices and lower production. In addition, we received a $0.4 million from a one-time positive severance tax adjustment related to our non-operated Eagle Ford operations. On a per Boe basis, taxes other than income were $2.86 and $4.38 for the six months ended June 30, 2023 and 2022, respectively.

DD&A expense was $12.9 million and $11.5 million for the six months ended June 30, 2023 and 2022, respectively. The change in DD&A expense was primarily due to a decrease in production of 23 MBoe, which equates to a decrease of $0.1 million in the change in production offset by an increase of $1.5 million in the change in our depletion rate.

General and administrative expense was $16.3 million and $16.4 million for the six months ended June 30, 2023 and 2022, respectively. The change in general and administrative expenses was primarily related to (i) an increase of $0.6 million in salaries and other payroll benefits, and (ii) an increase of $0.8 million in stock compensation expense, offset by a (i) a decrease of $0.4 million in professional services, and (ii) a decrease of $1.1 million in legal expense.

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Net gain on commodity derivative instruments of $19.0 million were recognized for the six months ended June 30, 2023, consisting of a $20.1 million increase in the fair value of open positions partially offset by $1.2 million of cash settlements paid on expired positions. Net loss on commodity derivative instruments of $112.0 million was recognized for the six months ended June 30, 2022, consisting of a $32.4 million decrease in the fair value of open positions and $79.5 million of cash settlements paid on expired positions.

Pipeline incident loss was $15.1 million and $5.7 million for the six months ended June 30, 2023 and 2022, respectively. The costs reflect certain expenses that are not expected to be recovered under an insurance policy. See Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Litigation settlement was $84.9 million for the six months ended June 30, 2023, related to the settlement with the shipping companies related to the containerships’ anchor strikes of the Company’s pipeline. See additional information discussed in Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. No litigation settlement was recorded for the six months ended June 30, 2022.

Interest expense, net was $9.4 million and $5.5 million for the six months ended June 30, 2023 and 2022, respectively. We had an increase of $2.7 million in interest expense due to higher interest rates offset by lower debt outstanding, an increase of $0.4 million in the amortization and write-off of debt issuance costs, and a change of $0.8 million in the change in interest rate swaps.

Average outstanding borrowings under our Revolving Credit Facility were $157.9 million and $223.7 million for the six months ended June 30, 2023 and 2022, respectively.

Current income tax benefit (expense) was ($5.7) million for the six months ended June 30, 2023. See additional information discussed in Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. No current income tax expense was recorded for the six months ended June 30, 2022.

Deferred income tax benefit (expense) was $259.4 million for the six months ended June 30, 2023. Starting in the first quarter of 2023, we achieved three years of cumulative income which allowed the release of the valuation allowance. See additional information discussed in Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. No deferred income tax benefit was recorded for the six months ended June 30, 2022.

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;

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● 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;

● 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, we use 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 Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
	(In thousands)
Net income (loss)	$	9,816	$	29,220	$	362,575	$	(19,394)
Interest expense, net		3,701		3,084		9,438		5,525
Income tax expense (benefit) - current		(6,853)		—		5,674		—
Income tax expense (benefit) - deferred		48		—		(259,422)		—
DD&A		7,072		5,864		12,880		11,499
Accretion of AROs		1,975		1,749		3,917		3,469
Losses (gains) on commodity derivative instruments		(3,798)		18,571		(18,957)		111,975
Cash settlements (paid) received on expired commodity derivative instruments		1,517		(48,596)		(1,192)		(79,539)
Pipeline incident loss		6,844		5,092		15,123		5,672
Litigation settlement		—		—		(84,875)		—
Share-based compensation expense		1,340		856		2,281		1,496
Loss on settlement of AROs		239		396		239		415
Exploration costs		14		10		40		26
Acquisition and divestiture related expenses		—		36		—		41
Bad debt expense		85		(4)		85		6
LOPI - timing difference		(4,636)		—		(4,636)		—
Other		188		—		188		—
Adjusted EBITDA	$	17,552	$	16,278	$	43,358	$	41,191

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

	For the Three Months Ended				For the Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
	(In thousands)
Net cash provided by operating activities	$	4,908	$	20,677	$	95,221	$	30,396
Changes in working capital		13,168		(13,582)		7,428		(2,209)
Interest expense, net		3,701		3,084		9,438		5,525
Pipeline incident loss		6,844		5,092		15,123		5,672
Litigation settlement		—		—		(84,875)		—
Income tax expense (benefit) - current		(6,853)		—		5,674		—
Amortization and write-off of deferred financing fees		(310)		(203)		(771)		(336)
Exploration costs		14		10		40		26
Gain (loss) on interest rate swaps		—		286		—		843
Cash settlements paid (received) on interest rate swaps		—		93		—		307
Plugging and abandonment cost		528		785		528		804
Acquisition and divestiture related expenses		—		36		—		41
LOPI - timing difference		(4,636)		—		(4,636)		—
Other		188		—		188		122
Adjusted EBITDA	$	17,552	$	16,278	$	43,358	$	41,191

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Liquidity and Capital Resources

Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities and borrowings under our Revolving Credit Facility. As we pursue reserve and production growth, we plan to monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our New Credit Facility will provide us with the financial flexibility necessary to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2023 development activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. For the remainder of 2023, we expect our primary funding sources to be from internally generated cash flow, borrowings under our New Credit Facility, and equity and debt capital markets.

Impact of the Southern California Pipeline Incident. We have incurred and will continue to incur certain costs as a result of the Incident.

We carry customary insurance policies, which have covered a material portion of the aggregate costs, including LOPI insurance, to offset loss of revenue resulting from suspended operations in Southern California. LOPI coverage specific to the Incident expired on March 31, 2023. 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.

In connection with the settlement between the Company and the vessels that struck and damaged the pipeline and their respective owners and operators, the Company received a net payment of approximately $85.0 million. Proceeds from the settlement have been used to reduce debt outstanding under the Company’s credit facility and to enhance liquidity.

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

Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 50% - 75% of our estimated production from total proved developed producing reserves over a one-to-three-year period at any given point of time. 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.

Valuation Allowance. Net deferred tax assets relate to net operating loss carryforwards, interest expense carryforwards, tax credits, and other temporary differences expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific federal and state tax jurisdictions in which those temporary differences are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion of or all our deferred tax assets will not be realized. On December 31, 2022, our valuation allowance was $284.9 million, which offset all net deferred tax assets as of such date.

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As of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. The assessment considers all available information including historical and forecasted taxable income and operating history. The three months ended March 31, 2023 marked the first time that we had achieved three years of cumulative income. Furthermore, management determined that our ability to maintain long-term profitability despite near-term changes in commodity prices and capital and operating costs demonstrated that there is sufficient positive evidence to conclude that it is more likely than not that all net deferred tax asset is realizable. As a result of our assessment, during the quarter ended June 30, 2023, we released substantially all of our valuation allowance previously recorded. The result of the valuation allowance release during the six months ended June 30, 2023 was a tax benefit of $279.3 million.

Capital Expenditures. Our total capital expenditures were approximately $16.9 million for the six months ended June 30, 2023, which were primarily related to capital workovers and facilities upgrades located in Oklahoma and California and non-operated drilling and completion activities in the Eagle Ford.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable, as well as the classification of our debt outstanding. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.

As of June 30, 2023, we had a working capital deficit of $12.7 million primarily due to accrued liabilities of $55.4 million, revenues payable of $21.5 million, accounts payable of $23.4 million and short-term derivatives of $0.7 million, partially offset by accounts receivable of $63.0 million, prepaid expenses of $23.5 million and cash on hand of $1.9 million.

Debt Agreement

Revolving Credit Facility. On November 2, 2018, OLLC, as borrower, entered into the Revolving Credit Facility (as amended and supplemented to date). KeyBank National Association serves as the administrative agent.

On July 31, 2023, OLLC and Acquisitionco entered into the New Credit Facility. The New Credit Facility is a replacement in full of the Revolving Credit Facility. The aggregate principal amount of loans outstanding under the New Credit Facility as of July 31, 2023, was $120.0 million. The initial borrowing base under the facility is $150.0 million, with elected commitments of $135.0 million, and, consistent with the prior Revolving Credit Facility, the New Credit Facility borrowing base will be redetermined on a semi-annual basis with the next redetermination expected to occur in the fourth quarter of 2023.

For additional information regarding our Revolving Credit Facility and New Credit Facility, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Material Cash Requirements

Contractual commitments. We have contractual commitments under our debt agreements, including interest payments and principal payments. 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.

Lease Obligations. We have operating leases for office and warehouse spaces, office equipment, compressors and surface rentals related to our business obligations. See Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

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Sinking fund payments. We have a funding requirement to fund a trust account to comply with supplemental regulatory bonding requirements related to our decommissioning obligations for our offshore Southern California production facilities. As of June 30, 2023, our future commitment under this agreement were $4.0 million for the remaining of 2023, and $15.8 million a year for years 2024 through 2033. See Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the six months ended June 30, 2023 and 2022 have been derived from our Unaudited Condensed Consolidated Financial Statements. For information regarding the individual components of our cash flow amounts, see our Unaudited Condensed Consolidated Statements of Cash Flows included under “Item 1. Financial Statements” of this quarterly report.

	For the Six Months Ended
	June 30,
	2023		2022
	(In thousands)
Net cash provided by operating activities	$	95,221	$	30,396
Net cash used in investing activities		(21,149)		(16,914)
Net cash used in financing activities		(72,207)		(15,590)

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $95.2 million and $30.4 million for the six months ended June 30, 2023 and 2022, respectively. Production volumes were approximately 20.3 MBoe/d and 20.4 MBoe/d for the six months ended June 30, 2023 and 2022, respectively. The average realized sales price was $36.40 per Boe and $55.95 per Boe for the six months ended June 30, 2023 and 2022, respectively. The change in average realized sales price was primarily due to the decrease in commodity prices.

Net cash provided by operating activities for the six months ended June 30, 2023 included $1.2 million of cash paid on expired commodity derivative instruments compared to $79.5 million of cash paid on expired commodity derivatives for the six months ended June 30, 2022. For the six months ended June 30, 2023, we had net gains on commodity derivative instruments of $19.0 million compared to net losses of $112.0 million for the six months ended June 30, 2022.

Investing Activities. Net cash used in investing activities for the six months ended June 30, 2023 was $21.1 million, of which $16.8 million was used for additions to oil and natural gas properties. Net cash provided by investing activities for the six months ended June 30, 2022 was $16.9 million, of which $12.9 million was used for additions to oil and natural gas properties.

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California properties. Additions to restricted investments were $4.2 million and $4.0 million during the six months ended June 30, 2023 and 2022, respectively.

Financing Activities. We had net repayments of $70.0 million and $15.0 million for the six months ended June 30, 2023 and 2022, respectively, related to our Revolving Credit Facility.

Off–Balance Sheet Arrangements

As of June 30, 2023, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

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

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ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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 June 30, 2023. 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.

For a discussion of the legal proceedings associated with the Incident, see Note 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report and the annual financial statements and related notes included in our 2022 Form 10-K.

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. There have been no material changes to the risk factors disclosed in Part I, Item 1A in our 2022 Form 10-K and Part II, Item 1A in our Form 10-Q filed on May 3, 2023.

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

The following table summarizes our repurchase activity during the three months ended June 30, 2023:

				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)
April 1, 2023 - April 30, 2023	710	$	7.24	—	n/a
May 1, 2023 - May 31, 2023	—	$	—	—	n/a
June 1, 2023 - June 30, 2023	—	$	—	—	n/a

(1) Common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. We 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.

ITEM 3.DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4.MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.OTHER INFORMATION.

None.

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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. (incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q (File No. 001-35512) filed on November 15, 2021).
10.1	—	Amended and Restated Credit Agreement dated July 31, 2023, among Amplify Energy Operating LLC, as borrower, Amplify Acquisitionco LLC, as parent, the lenders party thereto and KeyBank National Association, as administrative agent and a letter of credit issuer (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 1, 2023).
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

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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:	August 8, 2023	By:	/s/ James Frew
		Name:	James Frew
		Title:	Senior Vice President and Chief Financial Officer
Date:	August 8, 2023	By:	/s/ Eric Dulany
		Name:	Eric Dulany
		Title:	Vice President and Chief Accounting Officer

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