Table of Contents
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, 2025
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: (832) 219-9001
Not Applicable
(Former name or Former Address, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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
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 August 1, 2025, the registrant had 40,466,053 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, 2025 and December 31, 2024
Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2025 and 2024
9
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2025 and 2024
10
Unaudited Condensed Consolidated Statements of Equity (Deficit) for the Three and Six Months Ended June 30, 2025 and 2024
11
Notes to Unaudited Condensed Consolidated Financial Statements
12
Note 1 – Organization and Basis of Presentation
Note 2 – Summary of Significant Accounting Policies
Note 3 – Revenue
13
Note 4 – Acquisition and Divestitures
14
Note 5 – Fair Value Measurements of Financial Instruments
15
Note 6 – Risk Management and Derivative Instruments
17
Note 7 – Asset Retirement Obligations
19
Note 8 – Long-Term Debt
20
Note 9 – Equity
21
Note 10 – Earnings (Loss) per Share
22
Note 11 – Long-Term Incentive Plans
Note 12 – Leases
24
Note 13 – Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Consolidated Statements of Cash Flows
26
Note 14 – Related Party Transactions
27
Note 15 – Segment Reporting
Note 16 – Commitments and Contingencies
Note 17 – Income Taxes
29
Note 18 – Subsequent Events
30
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
31
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
43
Item 4.
Controls and Procedures
PART II—OTHER INFORMATION
Legal Proceedings
44
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Defaults Upon Senior Securities
Mine Safety Disclosures
Item 5.
Other Information
Item 6.
Exhibits
45
Signatures
47
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.
BSEE: Bureau of Safety and Environmental Enforcement.
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.
Henry Hub: A distribution hub in Louisiana that serves as the delivery location for natural gas futures contracts on the New York Mercantile Exchange.
ICE: Inter-Continental Exchange.
MBbl: One thousand Bbls.
MBbls/d: One thousand Bbls per day.
MBoe: One thousand barrels of oil equivalent.
MBoe/d: One thousand barrels of oil equivalent per day.
MMBoe: One million barrels of oil equivalent.
Mcf: One thousand cubic feet of natural gas.
Mcf/d: One Mcf per day.
MMBtu: One million Btu.
MMcf: One million cubic feet of natural gas.
MMcfe: One million cubic feet of natural gas equivalent.
MMcfe/d: One MMcfe per day.
Net Production: Production that is owned by us less royalties and production due to others.
NGLs: The combination of ethane, propane, butane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
NYSE: New York Stock Exchange.
Oil: Oil and condensate.
Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
OPIS: Oil Price Information Service.
Plugging and Abandonment: Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface. Regulations of all states require plugging of abandoned wells.
Probabilistic Estimate: The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
2
Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an Analogous Reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Realized Price: The cash market price less all expected quality, transportation and demand adjustments.
Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.
SEC: The U.S. Securities and Exchange Commission.
Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
Workover: Operations on a producing well to restore or increase production.
WTI: West Texas Intermediate.
3
NAMES OF ENTITIES
As used in this Form 10-Q, unless indicated otherwise:
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:
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,” “could,” “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:
6
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, 2024 initially filed with the SEC on March 5, 2025 and amended on April 17, 2025 (“2024 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
ITEM 1.FINANCIAL STATEMENTS.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except outstanding shares)
June 30,
December 31,
2025
2024
ASSETS
Current assets:
Cash and cash equivalents
$
—
Accounts receivable, net (see Note 13)
34,692
39,713
Short-term derivative instruments
9,909
6,385
Prepaid expenses and other current assets
25,412
25,679
Total current assets
70,013
71,777
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method
886,441
942,981
Support equipment and facilities
153,825
150,511
Other
12,126
11,478
Accumulated depreciation, depletion and amortization
(668,463)
(718,752)
Property and equipment, net
383,929
386,218
Long-term derivative instruments
233
Restricted investments
35,093
29,993
Operating lease - long term right-of-use asset
4,136
4,540
Deferred tax asset
251,718
251,600
Assets held for sale - non-current assets
24,333
Other long-term assets
2,085
2,715
Total assets
771,307
747,076
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
30,303
13,231
Revenues payable
11,736
11,494
Accrued liabilities (see Note 13)
41,215
43,413
Total current liabilities
83,254
68,138
Long-term debt (see Note 8)
130,000
127,000
Asset retirement obligations
131,464
129,700
730
Operating lease liability
3,268
3,683
Assets held for sale - non-current liabilities
1,333
Other long-term liabilities
9,953
9,643
Total liabilities
360,002
338,164
Commitments and contingencies (see Note 16)
Stockholders' equity (deficit):
Preferred stock, $0.01 par value: 50,000,000 shares authorized; no shares issued and outstanding at June 30, 2025 and December 31, 2024
Common stock, $0.01 par value: 250,000,000 shares authorized; 40,396,165 and 39,795,138 shares issued and outstanding at June 30, 2025 and December 31, 2024, respectively
404
399
Additional paid-in capital
441,846
439,981
Accumulated deficit
(30,945)
(31,468)
Total stockholders' equity (deficit)
411,305
408,912
Total liabilities and equity
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Three Months Ended
For the Six Months Ended
Revenues:
Oil and natural gas sales
66,774
72,346
137,115
147,668
Other revenues
1,587
7,157
3,296
8,134
Total revenues
68,361
79,503
140,411
155,802
Costs and expenses:
Lease operating expense
38,622
36,311
76,039
74,595
Gathering, processing and transportation
4,723
4,895
9,009
9,669
Taxes other than income
4,299
4,631
8,683
9,542
Depreciation, depletion and amortization
9,765
7,827
18,259
16,066
Impairment expense
8,448
General and administrative expense
11,197
8,358
22,012
18,158
Accretion of asset retirement obligations
2,210
2,096
4,393
4,157
Loss (gain) on commodity derivative instruments
(22,162)
1,225
(7,845)
17,789
Pipeline incident loss
195
500
591
1,207
(Gain) loss on sale of properties
(1,545)
(7,796)
Other, net
50
108
53
149
Total costs and expenses
55,802
65,951
131,846
151,332
Operating income (loss)
12,559
13,552
8,565
4,470
Other income (expense):
Interest expense, net
(3,594)
(3,632)
(7,113)
(7,159)
Other income (expense)
(666)
(109)
(551)
(204)
Total other income (expense)
(4,260)
(3,741)
(7,664)
(7,363)
Income (loss) before income taxes
8,299
9,811
901
(2,893)
Income tax (expense) benefit - current
(495)
(557)
(496)
(1,952)
Income tax (expense) benefit - deferred
(1,420)
(2,135)
118
2,568
Net income (loss)
6,384
7,119
523
(2,277)
Allocation of net income (loss) to:
Net income (loss) available to common stockholders
6,039
6,773
496
Net income (loss) allocated to participating securities
345
346
Net income (loss) available to Amplify Energy Corp.
Earnings (loss) per share: (See Note 10)
Basic and diluted earnings (loss) per share
0.15
0.17
0.01
(0.06)
Weighted average common shares outstanding:
Basic and diluted
40,349
39,629
40,269
39,519
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss (gain) on derivative instruments
Cash settlements (paid) received on expired derivative instruments
5,284
7,983
Deferred income tax expense (benefit)
(118)
(2,568)
Share-based compensation (see Note 11)
3,880
3,298
Settlement of asset retirement obligations
(525)
(416)
Amortization and write-off of deferred financing costs
630
608
Bad debt expense
Changes in operating assets and liabilities:
Accounts receivable
4,968
2,763
Prepaid expenses and other assets
2,116
(2,784)
Payables and accrued liabilities
9,124
(21,544)
Net cash provided by operating activities
49,190
23,101
Cash flows from investing activities:
Additions to oil and gas properties
(52,227)
(38,616)
Additions to other property and equipment
(649)
(992)
Additions to restricted investments
(5,100)
(4,969)
Proceeds from the sale of oil and natural gas properties
7,796
Net cash used in investing activities
(50,180)
(44,577)
Cash flows from financing activities:
Advances on Revolving Credit Facility
74,000
53,000
Payments on Revolving Credit Facility
(71,000)
(50,000)
Shares withheld for taxes
(2,010)
(1,768)
Net cash used in financing activities
990
1,232
Net change in cash and cash equivalents
(20,244)
Cash and cash equivalents, beginning of period
20,746
Cash and cash equivalents, end of period
502
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (DEFICIT)
Stockholders' Equity
Additional
Accumulated
Common
Paid-in
Earnings
Stock
Capital
(Deficit)
Total
Balance at December 31, 2024
(5,861)
Share-based compensation expense
1,890
(2,004)
(5)
Balance at March 31, 2025
439,862
(37,329)
402,937
1,990
(6)
Balance at June 30, 2025
Stockholders' Equity (Deficit)
Balance at December 31, 2023
393
435,095
(44,452)
391,036
(9,396)
1,120
(1,745)
Balance at March 31, 2024
398
434,465
(53,848)
381,015
2,140
38
2,178
(23)
Balance at June 30, 2024
436,582
(46,691)
390,289
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, par value $0.01 per share (“Common Stock”), is listed on the NYSE under the symbol “AMPY.”
The Company operates in one reportable segment that is engaged in the acquisition, development, exploitation and production of oil and natural gas properties. The Company’s management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of the Company’s oil and natural gas properties. The Company’s assets have historically consisted primarily of producing oil and natural gas properties located in Oklahoma, the Rockies (“Bairoil”), federal waters offshore Southern California (“Beta”), East Texas/North Louisiana and the Eagle Ford (non-op). Most of the Company’s oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.
Basis of Presentation
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 2024 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.
Segments
Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker (“CODM”). The Company’s Chief Executive Officer has been determined to be the Company’s CODM and as such, he allocates resources and assesses performance based upon consolidated financial information. See additional information in Note 15.
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 2024 Form 10-K.
New Accounting Pronouncements
Improvements to Income Tax Disclosure. In December 2023, the Federal Accounting Standards Board (the “FASB”) issued an accounting standard update which requires that companies disclose the nature and magnitude of factors contributing to the difference between their effective tax rate and the statutory tax rate. The update will require companies to disclose specific categories in the rate reconciliation and provide additional information about items that meet a certain quantitative threshold. The guidance is effective for annual periods beginning after December 15, 2024. The Company plans to adopt the guidance during fiscal year 2025, with the first disclosure to be reflected in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025. The Company is currently evaluating the impact of this guidance on the Company’s financial disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.
Income Statement –Expense Disaggregation Disclosures. In November 2024, the FASB issued an accounting standard update which requires disaggregated disclosures of income statement expenses for public business entities. The guidance will require companies to disclose disaggregated information about specific natural expense categories underlying certain income statement expense line items that are considered relevant because they include one or more of the five natural expense categories, as applicable: (1) purchase of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization and (5) depreciation, depletion and amortization (“DD&A”) recognized as part of oil and gas producing activities or other depletion expenses. The new guidance is effective for annual periods beginning after December 15, 2026 and interim periods within fiscal years beginning after December 31, 2027. The Company is currently evaluating the impact of this guidance on the Company’s financial disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
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 and (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.
Revenues
Oil
49,705
57,789
99,686
115,210
NGLs
5,648
6,565
11,806
14,091
Natural gas
11,421
7,992
25,623
18,367
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 were $28.8 million at June 30, 2025 and $28.5 million at December 31, 2024.
Note 4. Acquisitions and Divestitures
Assets Held for Sale
On June 30, 2025, the Company approved the plan to sell its non-operated Eagle Ford assets. On July 1, 2025, OLLC entered into a definitive agreement (the “Purchase and Sale Agreement”) to divest its non-core assets in the Eagle Ford for a contract price of $23.0 million, subject to certain post-closing adjustments (the “Asset Sale”). The assets held for sale are recorded at the lower of their carrying value or fair value less cost to sell. The Company recognized an impairment expense of approximately $8.4 million for both the three and six months ended June 30, 2025 in connection with the planned divestiture. The disposition did not qualify as discontinued operations. The major categories of assets and liabilities classified as held for sale were:
June 30, 2025
Assets classified as held for sale
101,330
Accumulated depreciation, depletion, and impairment
(76,997)
Total assets classified as held for sale
Liabilities associated with assets held for sale
(1,333)
Total liabilities associated with assets held for sale
East Texas Haynesville Monetization
On January 15, 2025, the Company sold 90% of its interest in certain units with rights in the Haynesville basin in Harrison County, Texas and purchased a 10% interest in adjacent acreage, generating $6.3 million in net proceeds from the transactions. These transactions also established an area of mutual interest with the counterparty covering 10,000 gross acres. Amplify retained a 10% working interest in the units it divested and purchased a 10% working interest in the counterparty’s acreage. The net proceeds received from the purchase and sale transactions of $6.3 million is classified as a (gain) loss on sale of properties in our Unaudited Consolidated Statement of Operations.
On May 1, 2025, the Company sold 90% of its interest in three additional units with rights in the Haynesville basin in Panola and Shelby Counties, Texas to a third party. Amplify retained a 10% working interest in the units it divested. The net proceeds from the transaction of $1.5 million are classified as a (gain) loss on sale of properties in our Unaudited Consolidated Statement of Operations.
Contemplated Merger with Juniper Capital
On January 14, 2025, the Company entered into an Agreement and Plan of Merger, as subsequently amended (the “Merger Agreement”) with Amplify DJ Operating LLC, a Delaware limited liability company and indirect wholly owned subsidiary of the Company (“First Merger Sub”), Amplify PRB Operating LLC, a Delaware limited liability company and indirect wholly owned subsidiary of Amplify (“Second Merger Sub”), North Peak Oil & Gas, LLC, a Delaware limited liability company (“NPOG”), Century Oil and Gas Sub-Holdings, LLC, a Delaware limited liability company (“COG” and, together with NPOG, the “Acquired Companies”), and, solely for the limited purposes set forth in the Merger Agreement, Juniper Capital Advisors, L.P. (“Juniper Capital”) and the Specified Company Entities set forth on Annex A thereto, pursuant to which, at the effective time of the Contemplated Mergers (as defined below) (the “Effective Time”), it was contemplated that (i) NPOG would merge with and into First Merger Sub, with NPOG surviving the merger as an indirect, wholly owned subsidiary of the Company and (ii) COG would merge with and into Second Merger Sub, with COG surviving the merger as an indirect, wholly owned subsidiary of the Company, in each case, subject to the terms and conditions of the Merger Agreement (clauses (i) and (ii), together, the “Contemplated Mergers”).
On April 25, 2025, pursuant to Section 8.1(a) of the Merger Agreement, the Company and the Acquired Companies entered into a mutual termination agreement (the “Termination Agreement”) to terminate the Merger Agreement (the “Termination”), effective immediately. As a result of the Termination Agreement, the Merger Agreement is of no further force and effect.
Acquisition and Divesture Expenses
Acquisition and divestiture related expenses for third-party transactions are included in general and administrative expense in the accompanying Unaudited Condensed Statement of Consolidated Operations for the periods indicated below (in thousands):
2,346
3,975
23
Note 5. Fair Value Measurements of Financial Instruments
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All the derivative instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets were considered Level 2.
The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying Unaudited Condensed Consolidated Balance Sheets approximated fair value at June 30, 2025 and December 31, 2024. 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, 2025 and December 31, 2024 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, 2025 and December 31, 2024 for each of the fair value hierarchy levels:
Fair Value Measurements at June 30, 2025
Significant
Quoted Prices in
Significant Other
Unobservable
Active Market
Observable Inputs
Inputs
(Level 1)
(Level 2)
(Level 3)
Fair Value
Assets:
Commodity derivatives
24,694
Interest rate derivatives
Liabilities:
15,515
Fair Value Measurements at December 31, 2024
14,317
7,699
See Note 6 for additional information regarding the Company’s derivative instruments.
16
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:
Note 6. 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 are generally 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. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, the Company would have the right to offset $9.9 million against amounts outstanding under the Revolving Credit Facility at June 30, 2025. See Note 8 for additional information regarding the Company’s Revolving Credit Facility.
Commodity Derivatives
The Company may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options and costless collars) to manage exposure to commodity price volatility. The Company recognizes all derivative instruments at fair value.
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, 2025, the Company had the following open commodity positions:
Remaining
2026
2027
2028
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average monthly volume (MMBtu)
560,000
515,000
197,500
20,000
Weighted-average fixed price
3.75
3.80
3.96
3.86
Collar contracts:
Two-way collars
500,000
517,500
640,000
67,500
Weighted-average floor price
3.50
3.58
3.54
Weighted-average ceiling price
3.90
4.11
4.31
4.52
Crude Oil Derivative Contracts:
Average monthly volume (Bbls)
170,000
146,500
45,667
70.32
65.77
62.57
17,000
70.00
80.20
18
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, 2025 and December 31, 2024. 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.
Asset
Liability
Derivatives
Type
Balance Sheet Location
Commodity contracts
15,397
5,488
9,499
3,114
Interest rate swaps
Gross fair value
Netting arrangements
(5,488)
(3,114)
Net recorded fair value
9,297
10,027
4,818
4,585
(9,297)
(4,585)
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 Operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):
Statements of
Operations Location
Commodity derivative contracts
Loss (gain) on commodity derivatives
Note 7. Asset Retirement Obligations
The Company’s asset retirement obligations primarily relate to the Company’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2025 (in thousands):
Asset retirement obligations at beginning of period
131,077
Liabilities added from acquisition or drilling
Liabilities settled
Liabilities removed upon sale of wells
(797)
Accretion expense
Revision of estimates
Asset retirement obligation at end of period
134,174
Less: Current portion
1,377
Less: Long-term portion - assets held for sale
Asset retirement obligations - long-term portion
Note 8. Long-Term Debt
The following table presents the Company’s consolidated debt obligations at the dates indicated:
Revolving Credit Facility (1)
Total long-term debt
Amended and Restated Credit Agreement
On July 31, 2023, OLLC and Amplify Acquisitionco LLC (“Acquisitionco”), as the direct parent of OLLC and wholly owned subsidiary of the Company, entered into the Amended and Restated Credit Agreement, providing for a senior secured reserve-based revolving credit facility. The Revolving Credit Facility is guaranteed by the Company and all of its material subsidiaries and secured by substantially all of its assets. The Revolving Credit Facility matures on July 31, 2027. KeyBank National Association is the administrative agent.
The aggregate principal amount of loans outstanding under the Revolving Credit Facility as of June 30, 2025, was $130.0 million. As of June 30, 2025, the borrowing base under the facility was $145.0 million with elected commitments of $145.0 million. The Revolving Credit Facility borrowing base is subject to redetermination on at least a semi-annual basis, primarily based on a reserve engineering report.
Certain key terms and conditions under the Revolving Credit Facility include (but are not limited to):
On May 29, 2025, the Company completed the spring redetermination which affirmed the borrowing base at $145.0 million. The next regularly schedule borrowing base redetermination is expected to occur in the fourth quarter of 2025.
As noted above, the Company is required to maintain a minimum current ratio of 1.00 to 1.00, which is measured on the last day of each quarter. On June 30, 2025, the Company’s current ratio was 0.90 to 1.00. On July 31, 2025, the Company received a letter agreement from its lenders waiving any default or event of default as a result of such noncompliance related to the minimum current ratio requirement for the quarter ended June 30, 2025. As a result, the Company was in compliance with all financial covenants as of June 30, 2025.
Subsequent Event. On July 2, 2025, subsequent to the Asset Sale, the Company’s borrowing base was reduced to $135.0 million.
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:
Revolving Credit Facility
8.40
%
9.35
8.43
9.37
Letters of Credit
At June 30, 2025, the Company had no letters of credit outstanding.
Unamortized Deferred Financing Costs
Unamortized deferred financing costs associated with the Company’s Revolving Credit Facility were $2.6 million at June 30, 2025.
Note 9. Equity
The Company’s authorized capital stock includes 250,000,000 shares of Common Stock. The following is a summary of the changes in the Company’s Common Stock issued for the six months ended June 30, 2025:
Balance, December 31, 2024
39,795,138
Issuance of Common Stock
Restricted stock units vested
917,521
Shares withheld for taxes (1)
(316,494)
Balance, June 30, 2025
40,396,165
Note 10. Earnings (Loss) 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):
Less: Net income allocated to participating securities
Basic and diluted earnings available to common stockholders
Common shares:
Common shares outstanding — basic
Dilutive effect of potential common shares
Common shares outstanding — diluted
Net earnings (loss) per share:
Basic
Diluted
Note 11. Long-Term Incentive Plans
On May 15, 2024, the Company’s shareholders approved the Amplify Energy Corp. 2024 Equity Incentive Plan (the “2024 EIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the prior Legacy Equity Incentive Plan (“EIP,” and together with the 2024 EIP, the “EIP Plans”).
The 2024 EIP provides for awards that can be granted in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance awards, stock awards and other incentive awards. To the extent that an award, other than stock options or stock appreciation rights, under the 2024 EIP has expired or been forfeited or canceled for any reason without having been exercised in full, the unexercised award would then be available again for future grants under the 2024 EIP. The 2024 EIP is administered by the board of directors of the Company.
Restricted Stock Units
Restricted Stock Units with Service Vesting Condition
Restricted stock units with service vesting conditions (“TSUs”) are accounted for as either equity-classified awards or liability-classified awards. The Company considered its intent and ability to settle awards in cash or shares of stock in determining whether to classify the awards as equity or liability awards. Compensation costs for equity-classified awards are recorded as general and administrative expense. The fair value of liability-classified awards is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general administrative expense and are remeasured at fair value each reporting period.
As of June 30, 2025, TSU grants 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. The unrecognized cost associated with the TSUs was $7.2 million at June 30, 2025. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted average period of approximately 2.0 years.
The following table summarizes information regarding the TSUs activity for the period presented:
Weighted-
Average Grant-
Number of
Date Fair Value
Units
per Unit (1)
TSUs outstanding at December 31, 2024
1,379,356
6.43
Granted (2)
817,666
5.34
Forfeited
(2,533)
Vested
(669,581)
5.99
TSUs outstanding at June 30, 2025
1,524,908
6.04
Restricted Stock Units with Market and Service Vesting Conditions
Restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as either equity-classified or liability-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. Vesting of PSUs can range from 0% to 200% of the target awards 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.
The 2023, 2024 and 2025 PSU awards are accounted for as equity-classified awards and 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 2023 awards is January 1, 2023 through December 31, 2025. The three-year performance period for the 2024 awards is January 1, 2024 through December 31, 2026. The three-year performance period for the 2025 awards is January 1, 2025 through December 31, 2027.
Compensation costs related to PSU awards are recorded as general and administrative expense. The unrecognized cost associated with PSU awards was $4.2 million at June 30, 2025. The Company expects to recognize the unrecognized compensation cost for PSU awards over a weighted-average period of approximately 2.0 years.
The below table reflects the ranges for the assumptions used in the Monte Carlo model for the 2025 PSUs:
February 2025
Expected volatility
58.6
Dividend yield
0.00
Risk-free interest rate
4.22
The following table summarizes information regarding the PSU activity for the period presented:
PRSUs outstanding at December 31, 2024
608,500
9.58
495,783
6.84
(247,940)
6.20
PRSUs outstanding at June 30, 2025
856,343
8.97
Compensation Expense
The following table summarizes the amount of recognized compensation expense associated with the EIP Plans, which are reflected in the accompanying Unaudited Condensed Consolidated Statements of Operations for the periods presented (in thousands):
Share-based compensation costs
TSUs
1,335
1,272
2,623
2,363
PRSUs
656
495
1,257
935
1,991
1,767
Note 12. Leases
The Company has leases for office space, warehouse space and equipment in its corporate office and operating regions as well as vehicles, compressors and surface rentals related to its business operations. In addition, the Company has right-of-way leases to operate the San Pedro Bay Pipeline. 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, 2025, 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.
The Company’s corporate office lease does not provide an implicit rate. To determine the present value of the lease payments, the Company uses an 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, 2025 and 2024, the Company recognized approximately $1.1 million and $1.0 million, respectively, of costs relating to the operating leases in the Unaudited Condensed Consolidated Statements of Operations.
Supplemental cash flow information related to the Company’s lease liabilities is included in the table below:
Non-cash amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
744
The following table presents the Company’s right-of-use assets and lease liabilities for the period presented:
Right-of-use asset
Lease liabilities:
Current lease liability
1,716
1,784
Long-term lease liability
Total lease liability
4,984
5,467
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
722
373
1,095
1,218
423
1,641
843
329
1,172
724
731
2029 and thereafter
1,087
Total lease payments
4,594
1,132
5,726
Less: interest
646
96
742
Present value of lease liabilities
3,948
1,036
The weighted average remaining lease terms and discount rate for all of the Company’s operating leases for the period presented:
Weighted average remaining lease term (years):
Office and warehouse space
3.29
4.08
Vehicles
0.41
0.19
Office equipment
Weighted average discount rate:
5.44
1.66
1.09
0.05
25
Note 13. Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Consolidated Statements of Cash Flows
Accrued Liabilities
Current accrued liabilities consisted of the following at the dates indicated (in thousands):
Accrued lease operating expense
11,187
13,845
Accrued capital expenditures
11,483
5,191
Accrued general and administrative expense
4,941
6,281
Accrued production and ad valorem tax
2,910
2,827
Accrued commitment fee and other expense
2,305
2,395
Accrued interest payable
376
292
Accrued liability - pipeline incident
1,100
5,534
Accrued current income tax payable
482
116
3,338
3,771
Accrued liabilities
Accounts Receivable
Accounts receivable consisted of the following at the dates indicated (in thousands):
Oil and natural gas receivables
28,757
28,505
Insurance receivable - pipeline incident
396
4,722
Joint interest owners and other
7,320
8,214
Total accounts receivable
36,473
41,441
Less: allowance for doubtful accounts
(1,781)
(1,728)
Total accounts receivable, net
Supplemental Cash Flows
Supplemental cash flows for the periods presented (in thousands):
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized
4,669
6,437
Cash paid for taxes
130
1,040
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities
6,292
(1,561)
Note 14. 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, 2025 and 2024.
Note 15. Segment Reporting
The Company’s operations are all related to the exploration, development and production of oil and natural gas in the United States, from which the Company derives all of its revenues. The Company manages its business as a single reportable segment, as its operations are focused on assets with similar economic characteristics, production processes, types of purchasers, regulatory environment and customers which are consistent across the Company. Therefore, the Company aggregates its operating regions into one reportable segment.
The CODM uses consolidated net income to assess financial performance, allocating capital and other resources. The CODM uses consolidated net income in the annual budgeting and monthly forecasting process. Additionally, the CODM is regularly provided information on lease operating expense, gathering, processing and transportation and taxes other than income. Other segment items primarily consist of DD&A, accretion expense, general and administrative expense, pipeline incident loss, loss (gain) on commodity derivative, interest expense and income tax expense (benefit). Our significant segment expenses and other segment items are derived from and can be found within the Unaudited Consolidated Statement of Operations.
Revenue
Less:
Other segment items
14,333
26,547
46,157
64,273
Note 16. 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.
Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At June 30, 2025 and December 31, 2024, the Company had no environmental reserves recorded in its Unaudited Condensed Consolidated Balance Sheet.
Termination of Contemplated Merger with Juniper Capital
In connection with the Contemplated Mergers, on April 25, 2025, pursuant to Section 8.1(a) of the Merger Agreement, the Company and the Acquired Companies entered into the Termination Agreement to terminate the Merger Agreement, effective immediately. As a result of the Termination Agreement, the Merger Agreement is of no further force and effect.
In accordance with the terms of the Termination Agreement, the Company made a cash payment to the Acquired Companies in lieu of any termination fee which might have otherwise been payable pursuant to the Merger Agreement in the amount of $800,000 as payment for certain of the Acquired Companies’ expenses. The Company and the Acquired Companies also agreed to release each other from certain claims and liabilities arising out of or related to the Merger Agreement or the transactions contemplated therein or thereby. The Company incurred professional fees and expenses of approximately $3.4 million in connection with the Contemplated Mergers and the Termination.
Beta Pipeline Incident
There have been no material changes to the legal proceedings, insurance receivables and costs associated with the incident that occurred at our producing oil property located at Beta (the “Incident”) as described in the Company’s annual financial statements included in its 2024 Form 10-K, except with respect to that disclosed below:
On June 30, 2025, and December 31, 2024, the Company’s insurance receivables were $0.4 million and $4.7 million, respectively. Excluding the costs associated with the resolution of the federal and state matters discussed in the 2024 Form 10-K, for the six months ended June 30, 2025, the Company incurred legal fees, loss load and other non-reimbursable expenses of $0.6 million that are classified as “Pipeline Incident Loss” on the Company’s Unaudited Condensed Consolidated Statements of Operations. For more information, please see the 2024 Form 10-K.
Sinking Fund Trust Agreement
Beta Operating Company, LLC (“Beta LLC”), a wholly owned subsidiary, assumed an obligation with a third party to make payments into a sinking fund in connection with the Company’s 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. 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, 2025, the account balance included in restricted investments was approximately $4.6 million.
Supplemental Bond for Decommissioning Liabilities Trust Agreement
Beta LLC has a decommissioning obligation with BOEM in connection with 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.
28
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 LLC properties. In March 2024, the Company amended one of the escrow funding agreements to decrease the amount funded from $14.8 million per year to $8.0 million per year. There were no changes made to the second escrow agreement. The obligation for these agreements ceases when the total aggregate value of the escrow accounts reaches $172.6 million.
The below table outlines the updated funding commitment for these agreements at June 30, 2025 (in thousands):
Payment Due by Period
Funding commitment
Remaining 2025
2029
Thereafter (1)
Federal escrow fund payments
133,763
4,000
8,000
97,763
State escrow fund payments
8,652
517
1,034
3,999
Total sinking fund payments
142,415
4,517
9,034
101,762
As of June 30, 2025, the Company has funded $30.5 million into the escrow accounts which is reflected in “Restricted investments” on the Unaudited Condensed Consolidated Balance Sheet.
Note 17. Income Taxes
The Company’s current income tax benefit (expense) was ($0.5) million for each of the three and six months ended June 30, 2025. The Company’s current income tax benefit (expense) was ($0.6) million and ($2.0) million for the three and six months ended June 30, 2024, respectively.
The Company’s deferred income tax benefit (expense) was ($1.4) million and $0.1 million for the three and six months ended June 30, 2025, respectively. The Company’s deferred income tax benefit (expense) was ($2.1) million and $2.6 million for the three and six months ended June 30, 2024, respectively.
The effective tax rates for the three and six months ended June 30, 2025 were 23.1% and 42.0%, respectively. The effective tax rates for the three and six months ended June 30, 2024 were 27.4% and 21.3%, respectively. 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, 2025 was primarily from higher discrete realized hedging income tax expense and lower book income in the second quarter of 2025. 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, 2024 was due to higher income earned in the second quarter of 2024.
On July 4, 2025, the President signed into law the One Big Beautiful Bill Act (“OBBBA”), which introduces significant changes to U.S. federal tax law. Key provisions of the legislation include modifications to the limitation on the deductibility of business interest expense, changes to the treatment of research and development expenditures, full expensing of qualified capital expenditures, and modifications to the international tax framework.
The Company is currently evaluating the impact of the OBBBA on its consolidated financial statements. While the full effects are still being assessed, the Company anticipates a reduction in current income tax expense for the year with no material impact to the effective tax rate.
Note 18. Subsequent Events
Sale of Non-Operated Eagle Ford Assets and Borrowing Base Redetermination
On July 1, 2025, OLLC entered into the Purchase and Sale Agreement with Murphy Exploration & Production Company – USA, a Delaware corporation (“Buyer”), the existing operator of the majority of OLLC’s Assets (as defined in the Purchase and Sale Agreement), pursuant to which OLLC sold to Buyer all of OLLC’s Assets, which include, among other things, OLLC’s right, title and interest in and to certain specified oil and gas Properties, Contracts, Equipment and Production (each, as defined in the Purchase and Sale Agreement) within or related to certain designated lands in Karnes County, Texas, for an aggregate cash purchase price of $23.0 million, subject to certain post-closing adjustments. The Asset Sale closed simultaneously with the execution and delivery of the Purchase and Sale Agreement on July 1, 2025. The Purchase and Sale Agreement became effective as of June 15, 2025.
Additionally, see Note 8 for additional information relating to the reduction in the Company’s borrowing base in connection with the Asset Sale.
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 2024 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 have historically consisted primarily of producing oil and natural gas properties located in Oklahoma, the Rockies (“Bairoil”), federal waters offshore Southern California (“Beta”), East Texas/North Louisiana and the Eagle Ford (non-op). Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs.
Industry Trends
We continue to monitor the impact of the actions of OPEC+ and other large producing nations, the Russia-Ukraine conflict, conflicts in the Middle East, the imposition of tariffs or other economic sanctions, global inventories of oil and natural gas and the uncertainty associated with recovering oil demand, inflation and future monetary policy and governmental policies aimed at transitioning towards lower carbon energy. In the first half of 2025, there has been continued volatility in oil, natural gas and NGL prices resulting from (i) trade tariff uncertainties driving concerns over an increase in inflation and (ii) OPEC+’s decision to increase production in May through July 2025, creating additional global supply and further downward pressure on oil prices. In July 2025, OPEC+ announced an additional production increase for August, which is expected to exacerbate these supply-side pressures on oil prices.
While U.S. inflation rates during the first half of 2025 have remained relatively stable, they continued to be slightly higher than historical averages. Such inflation, along with the effects of economic pressures from international military and trade conflicts, could, as a result, continue to raise the cost of borrowing, impact the demand for and price of oil and natural gas, increase the price of crucial supplies and raw materials and impact interest rates. Due to these factors, among others, we expect prices for some or all commodities to remain volatile. Thus, we cannot predict with reasonable certainty the extent to which these factors may impact our business, results of operations, financial condition and cash flows.
Recent Developments
Strategic Initiatives
On July 22, 2025, we announced the engagement of a third-party advisor to explore market interest for the complete divestiture of Amplify’s assets in East Texas and Oklahoma.
Separation of Chief Executive Officer and Director
On July 21, 2025, the Company, and Mr. Martyn Willsher, the Company’s former President, Chief Executive Officer and member of the Company’s board of directors (the “Board”), agreed that (i) Mr. Willsher’s roles as President and Chief Executive Officer of the Company and a member of the Board terminated effective July 22, 2025 (the “Transition Date”), and (ii) Mr. Willsher assumed the non-executive employee role of Special Advisor to the Company on the Transition Date.
In connection with the transition of Mr. Willsher’s role, the Company and Mr. Willsher entered into a Transition and Separation Agreement (the “Transition Agreement”), effective as of the Transition Date. Pursuant to the terms of the Transition Agreement, Mr. Willsher will serve as Special Advisor to the Company until December 31, 2025, unless earlier terminated in accordance with the terms of the Transition Agreement. The Transition Agreement is filed as Exhibit 10.4 to this Current Report on Form 10-Q.
Appointment of Chief Executive Officer and Director
On July 21, 2025, the Board appointed Mr. Daniel Furbee, previously the Company’s Senior Vice President and Chief Operating Officer, to Chief Executive Officer and as a member of the Board, effective as of the Transition Date. In connection with Mr. Furbee’s appointment as Chief Executive Officer, Mr. Furbee and the Company entered into a performance-based restricted stock units award agreement (the “Award Agreement”). The Award Agreement is filed as Exhibit 10.5 to this Current Report on Form 10-Q.
Appointment of President and Chief Financial Officer
On July 21, 2025, the Board appointed Mr. James Frew, previously the Company’s Senior Vice President and Chief Financial Officer, to President and Chief Financial Officer, effective as of the Transition Date.
On July 1, 2025, OLLC entered into a purchase and sale agreement with Buyer, the existing operator of the majority of OLLC’s Assets, pursuant to which OLLC sold to Buyer all of OLLC’s Assets, which include, among other things, OLLC’s right, title and interest in and to certain specified oil and gas Properties, Contracts, Equipment and Production within or related to certain designated lands in Karnes County, Texas, for an aggregate cash purchase price of $23.0 million, subject to certain post-closing adjustments, as further described in the Purchase and Sale Agreement. The Asset Sale closed simultaneously with the execution and delivery of the Purchase and Sale Agreement on July 1, 2025. The Purchase and Sale Agreement became effective as of June 15, 2025.
On July 2, 2025, subsequent to the Asset Sale, our borrowing base was reduced to $135.0 million.
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 2024 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, 2025 and 2024 have been derived from our unaudited condensed consolidated financial statements.
The following table summarizes certain of the results of operations for the periods indicated.
($ In thousands except per unit amounts)
3,594
3,632
7,113
7,159
Oil and natural gas revenues:
Oil sales
NGL sales
Natural gas sales
Total oil and natural gas revenues
Production volumes:
Oil (MBbls)
828
756
1,565
1,542
NGLs (MBbls)
285
548
678
Natural gas (MMcf)
3,760
4,453
7,407
8,788
Total (MBoe)
1,740
1,843
3,347
3,685
Average net production (MBoe/d)
19.1
20.3
18.5
20.2
Average realized sales price (excluding commodity derivatives):
Oil (per Bbl)
60.01
76.51
63.69
74.71
NGL (per Bbl)
19.81
18.99
21.56
20.76
Natural gas (per Mcf)
3.04
1.79
3.46
2.09
Total (per Boe)
38.38
39.25
40.96
40.07
Average unit costs per Boe:
22.20
19.70
22.72
20.24
2.71
2.66
2.69
2.62
2.47
2.51
2.59
6.44
4.53
6.58
4.93
Depletion, depreciation and amortization
5.61
4.25
5.46
4.36
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For the Three Months Ended June 30, 2025 Compared to the Three Months Ended June 30, 2024
We reported net income of $6.4 million compared to net income of $7.1 million for the three months ended June 30, 2025 and 2024, respectively.
Oil, natural gas and NGL revenues were $66.8 million and $72.3 million for the three months ended June 30, 2025 and 2024, respectively. Average net production volumes were approximately 19.1 MBoe/d and 20.3 MBoe/d for the three months ended June 30, 2025 and 2024, respectively. The average realized sales prices were $38.38 per Boe and $39.25 per Boe for the three months ended June 30, 2025 and 2024, respectively. The change in realized sales price was due to lower realized sales prices for oil, partially offset by higher realized sales prices for natural gas.
Other revenues were $1.6 million and $7.2 million for the three months ended June 30, 2025 and 2024, respectively. The decrease primarily related to the revenue suspense release of $4.8 million for the three months ended June 30, 2024.
Lease operating expenses were $38.6 million and $36.3 million for the three months ended June 30, 2025 and 2024, respectively. On a per Boe basis, lease operating expenses were $22.20 and $19.70 for the three months ended June 30, 2025 and 2024, respectively. The change in lease operating expense is primarily due to increased electricity costs for Bairoil.
Gathering, processing and transportation expenses were $4.7 million and $4.9 million for the three months ended June 30, 2025 and 2024, respectively. On a per Boe basis, gathering, processing and transportation expenses were $2.71 and $2.66 for the three months ended June 30, 2025 and 2024, respectively. The change in gathering processing and transportation expenses was primarily due to lower gas volumes.
Taxes other than income were $4.3 million and $4.6 million for the three months ended June 30, 2025 and 2024, respectively. On a per Boe basis, taxes other than income were $2.47 and $2.51 for the three months ended June 30, 2025 and 2024, respectively. The decrease was primarily related to a reduction in production taxes based on lower volumes partially offset by an increase in emission charges and ad valorem taxes.
DD&A expenses were $9.8 million and $7.8 million for the three months ended June 30, 2025 and 2024, respectively. The change was primarily driven by increased production at Beta and Eagle Ford.
Impairment expense was $8.4 million for the three months ended June 30, 2025. The Company recognized an impairment expense to reduce the net book value of our non-operated Eagle Ford assets to fair value less costs to sell. See Note 4 and Note 18 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information. No impairment expense was recorded for the three months ended June 30, 2024.
General and administrative expenses were $11.2 million and $8.4 million for the three months ended June 30, 2025 and 2024, respectively. The change in general and administrative expenses was primarily related to an increase of $2.3 million in acquisition and divestiture costs incurred during the second quarter and an increase of $0.2 million in stock compensation expense.
Net loss (gain) on commodity derivative instruments of ($22.2) million were recognized for the three months ended June 30, 2025, consisting of a $17.4 million increase in the fair value of open positions and $4.8 million of cash settlements received on expired positions. Net loss on commodity derivative instruments of $1.2 million was recognized for the three months ended June 30, 2024, consisting of a $4.9 million decrease in the fair value of open positions, partially offset by $3.7 million of cash settlements received on expired positions.
Pipeline incident loss was $0.2 million and $0.5 million for the three months ended June 30, 2025 and 2024, respectively. The costs reflect certain expenses 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.
(Gain) loss on sale of properties was ($1.5) million for the six months ended June 30, 2025. This primarily related to the sale of certain units with rights in the Haynesville basin in Panola and Shelby Counties, Texas. See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information. There was no (gain) loss on sale of properties for the three months ended June 30, 2024.
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Interest expense, net was $3.6 million for both the three months ended June 30, 2025 and 2024, respectively.
Average outstanding borrowings under our Revolving Credit Facility were $130.5 million and $121.8 million for the three months ended June 30, 2025 and 2024, respectively.
Current income tax benefit (expense) was ($0.5) million and ($0.6) million for the three months ended June 30, 2025 and 2024, respectively. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Deferred income tax benefit (expense) was ($1.4) million and ($2.1) million for the three months ended June 30, 2025 and 2024, respectively. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
For the Six Months Ended June 30, 2025 Compared to the Six Months Ended June 30, 2024
We reported net income of $0.5 million compared to a net loss of $2.3 million for the six months ended June 30, 2025 and 2024, respectively.
Oil, natural gas and NGL revenues were $137.1 million and $147.7 million for the six months ended June 30, 2025 and 2024, respectively. Average net production volumes were approximately 18.5 MBoe/d and 20.2 MBoe/d for the six months ended June 30, 2025 and 2024, respectively. The average realized sales prices were $40.96 per Boe and $40.07 per Boe for the six months ended June 30, 2025 and 2024, respectively. The change in realized sales prices was due to higher natural gas and NGL prices, partially offset by lower realized sales prices for oil. In addition, oil production had a higher percentage of total production in the first half of 2025 when compared to the first half of 2024.
Other revenues were $3.3 million and $8.1 million for the six months ended June 30, 2025 and 2024, respectively. The decrease primarily related to the revenue suspense release of $4.8 million for the six months ended June 30, 2024.
Lease operating expenses were $76.0 million and $74.6 million for the six months ended June 30, 2025 and 2024, respectively. On a per Boe basis, lease operating expenses were $22.72 and $20.24 for the six months ended June 30, 2025 and 2024, respectively. The change in lease operating expense on a per Boe basis was primarily due to increased electricity costs for Bairoil.
Gathering, processing and transportation expenses were $9.0 million and $9.7 million for the six months ended June 30, 2025 and 2024, respectively. On a per Boe basis, gathering, processing and transportation expenses were $2.69 and $2.62 for the six months ended June 30, 2025 and 2024, respectively. The change in gathering, processing and transportation expense was primarily due to lower gas volumes.
Taxes other than income were $8.7 million and $9.5 million for the six months ended June 30, 2025 and 2024, respectively. On a per Boe basis, taxes other than income were $2.59 for each of the six months ended June 30, 2025 and 2024. The decrease was primarily related to a reduction in production taxes due to lower volumes partially offset by an increase in emissions charges and ad valorem tax.
DD&A expenses were $18.3 million and $16.1 million for the six months ended June 30, 2025 and 2024, respectively. The change is primarily due to an increase in our DD&A rate.
Impairment expense was $8.4 million for the six months ended June 30, 2025. The Company recognized an impairment expense to reduce the net book value of our non-operated Eagle Ford assets to fair value less costs to sell. See Note 4 and Note 18 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information. No impairment expense was recorded for the six months ended June 30, 2024.
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General and administrative expenses were $22.0 million and $18.2 million for the six months ended June 30, 2025 and 2024, respectively. The change in general and administrative expenses was primarily related to (i) an increase of $4.0 million in acquisition and divestiture costs and (ii) an increase of $0.6 million in stock compensation expense, partially offset by (i) a decrease of $0.5 million in office lease expense related to the early termination of our Oklahoma office lease in 2024 and (ii) a decrease of $0.3 million for salaries and other payroll benefits.
Net loss (gain) on commodity derivative instruments of ($7.8) million was recognized for the six months ended June 30, 2025, consisting of a $2.6 million increase in the fair value of open positions and $5.3 million of cash settlements received on expired positions. A net loss on commodity derivative instruments of $17.8 million was recognized for the six months ended June 30, 2024, consisting of a $25.8 million decrease in the fair value of open positions, partially offset by $8.0 million of cash settlements received on expired positions.
Pipeline incident loss was $0.6 million and $1.2 million for the six months ended June 30, 2025 and 2024, respectively. The costs reflect certain expenses 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.
(Gain) loss on sale of properties was ($7.8) million for the six months ended June 30, 2025. This primarily related to the sale of certain units with rights in the Haynesville basin in Harrison County, Texas. See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information. There was no (gain) loss on sale of properties for the six months ended June 30, 2024.
Interest expense, net was $7.1 million and $7.2 million for the six months ended June 30, 2025 and 2024, respectively.
Average outstanding borrowings under our Revolving Credit Facility were $128.9 million and $118.5 million for the six months ended June 30, 2025 and 2024, respectively.
Current income tax benefit (expense) was ($0.5) million and ($2.0) million for the six months ended June 30, 2025 and 2024, respectively. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Deferred income tax benefit (expense) was $0.1 million and $2.6 million for the six months ended June 30, 2025 and 2024, respectively. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Non-GAAP Financial Measures
We include in this report the non-GAAP financial measure of Adjusted Net Income (Loss) and Adjusted EBITDA and provide our reconciliation of net income (loss) to Adjusted Net Income (Loss), 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.
Adjusted Net Income (Loss)
We define Adjusted Net Income (Loss) as net income (loss) adjusted for unrealized loss (gain) on commodity derivative instruments, acquisition and divestiture-related expenses, impairment expense, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our federal statutory tax rate. This measure is not meant to disassociate these items from management’s performance but rather is intended to provide helpful information to investors interested in comparing our performance between periods. Adjusted Net Income (Loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP.
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The following tables present our reconciliation of the Company’s net income (loss) to Adjusted Net Income (Loss), our most directly comparable GAAP financial measures, for each of the periods indicated.
Net (loss) income
Unrealized loss (gain) on commodity derivative instruments
(17,381)
4,905
(2,561)
25,772
Acquisition and divestiture-related expenses
Non-recurring costs:
Income tax expense (benefit) - deferred
1,420
2,135
Tax effect of adjustments (1)
(1,942)
(2)
(972)
Adjusted net income (loss)
(2,270)
14,166
1,499
20,945
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. We define Adjusted EBITDA as net income (loss):
Plus:
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We believe 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 as an additional measure 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) to Adjusted EBITDA and cash flows from operating activities to Adjusted EBITDA, our most directly comparable GAAP financial measures, for each of the periods indicated.
Reconciliation of Net Income (Loss) to Adjusted EBITDA
Income tax expense (benefit) - current
557
1,952
DD&A
Accretion of AROs
Cash settlements (paid) received on expired commodity derivative instruments
4,781
3,680
Acquisition and divestiture related expenses
Amortization of gain associated with terminated commodity derivatives
159
318
Loss on settlement of AROs
40
98
Exploration costs
51
800
94
686
18,983
30,749
38,427
55,650
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
23,689
15,389
Changes in working capital
(10,836)
10,348
(16,208)
21,565
(Gain) loss on sale of property
Plugging and abandonment cost
391
514
562
Amortization and write-off of deferred financing fees
(315)
(304)
(630)
(608)
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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, borrowings under our Revolving Credit Facility and equity and debt capital markets. 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 Revolving 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 2025 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 2025, we anticipate funding our 2025 capital program from internally generated cash flow but retain the flexibility to utilize borrowings under our Revolving Credit Facility, to access the debt and equity capital markets and continue to evaluate opportunities to optimize our portfolio to reduce debt and accelerate Beta development. We believe that existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our Revolving Credit Facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter.
Termination of Contemplated Merger with Juniper Capital. In connection with the Contemplated Mergers, on April 25, 2025, pursuant to Section 8.1(a) of the Merger Agreement, the Company and the Acquired Companies entered into the Termination Agreement to terminate the Merger Agreement, effective immediately. In accordance with the terms of the Termination Agreement, the Company made a cash payment to the Acquired Companies in lieu of any termination fee which might have otherwise been payable pursuant to the Merger Agreement in the amount of $800,000 as payment for certain of the Acquired Companies’ expenses. The Company incurred professional fees and expenses of approximately $3.4 million in connection with the Contemplated Mergers and the Termination. For additional information regarding the Termination, see Notes 4 and 16 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
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 capital needs.
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. 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 a loss.
Capital Expenditures. Our total capital expenditures were approximately $48.6 million for the six months ended June 30, 2025, which were primarily related to the development program at Beta and non-operated drilling and completion activities in East Texas and 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. From time-to-time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual.
As of June 30, 2025, we had a working capital deficit (excluding commodity derivatives) of $23.2 million primarily due to accrued liabilities of $41.2 million, revenues payable of $11.7 million, and accounts payable of $30.3 million, partially offset by accounts receivable of $34.7 million and prepaid expenses of $25.4 million.
Debt Agreement
Revolving Credit Facility. On July 31, 2023, OLLC and Acquisitionco entered into the Revolving Credit Facility. The aggregate principal amount of loans outstanding under the Revolving Credit Facility as of June 30, 2025, was $130.0 million.
As of June 30, 2025, we had approximately $15.0 million of available borrowings under our Revolving Credit Facility.
The Company is required to maintain a minimum current ratio of 1.00 to 1.00, which is measured on the last day of each quarter. On June 30, 2025, the Company’s current ratio was 0.90 to 1.00. On July 31, 2025, the Company received a letter agreement from its lenders waiving any default or event of default as a result of such noncompliance related to the minimum current ratio requirement for the quarter ended June 30, 2025. As a result, the Company was in compliance with all financial covenants as of June 30, 2025. The Company expects to maintain a current ratio of 1.0 to 1.0 in future quarters.
On July 2, 2025, subsequent to the divestiture of our non-op Eagle Ford assets, our borrowing base was reduced to $135.0 million.
For additional information regarding our Revolving Credit Facility, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Material Cash Requirements
Contractual Commitments. We have contractual commitments under our debt agreements, including interest payments and principal payments. See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Lease Obligations. We have operating leases for office and warehouse spaces, office equipment, compressors and surface rentals related to our business obligations. See Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Sinking Fund Payments. We have a funding requirement to fund two trust accounts to comply with supplemental regulatory bonding requirements related to our decommissioning obligations for the Beta production facilities. As of June 30, 2025, our future commitments under these agreements were $4.5 million for the remainder of 2025 and $9.0 million per year until the escrow accounts are fully funded. 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.
41
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, 2025 and 2024 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.
Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $49.2 million and $23.1 million for the six months ended June 30, 2025 and 2024, respectively.
Production volumes were approximately 18.5 MBoe/d and 20.2 MBoe/d for the six months ended June 30, 2025 and 2024, respectively. The average realized sales price was $40.96 per Boe and $40.07 per Boe for the six months ended June 30, 2025 and 2024, respectively. The change in realized sales prices was due to higher natural gas and NGL prices, partially offset by lower realized sales prices for oil. In addition, oil production had a higher percentage of total production in the first half of 2025 when compared to the first half of 2024.
Net cash provided by operating activities for the six months ended June 30, 2025 included $5.3 million of cash received on expired commodity derivative instruments compared to $8.0 million of cash received on expired commodity derivatives for the six months ended June 30, 2024. For the six months ended June 30, 2025, we had a net gain on commodity derivative instruments of $7.8 million compared to a net loss of $17.8 million for the six months ended June 30, 2024.
In addition, the six months ended June 30, 2025 included an impairment expense of $8.4 million for the loss on assets held for sale.
Investing Activities. Net cash used in investing activities for the six months ended June 30, 2025 was $50.2 million, of which $52.2 million was used for additions to oil and natural gas properties and $0.6 million for additions to other property and equipment. Net cash used in investing activities for the six months ended June 30, 2024 was $44.6 million, of which $38.6 million was used for additions to oil and natural gas properties and $1.0 million for additions to other property and equipment.
During 2025, we purchased and sold certain rights, title and interest in assets in East Texas from a third party, whereby we received net proceeds of $7.8 million. See additional information discussed in Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our Beta properties. Additions to restricted investments were $5.1 million and $5.0 million for the six months ended June 30, 2025 and 2024, respectively.
Financing Activities. We had net borrowings of $3.0 million for the six months ended June 30, 2025 related to our Revolving Credit Facility compared to net borrowings of $3.0 million for the six months ended June 30, 2024. Shares withheld for taxes were $2.0 million and $1.8 million for the six months ended June 30, 2025 and 2024, respectively.
Off–Balance Sheet Arrangements
As of June 30, 2025, we had no off–balance sheet arrangements.
42
Recently Issued Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
ITEM 4.CONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures
As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) 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, 2025. 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.
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 2024 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 2024 Form 10-K.
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, 2025:
Total Number of
Approximate Dollar
Shares Purchased as
Value of Shares That
Part of Publicly
May Yet Be
Average Price
Announced Plans
Purchased Under the
Period
Shares Purchased
Paid per Share
or Programs
Plans or Programs (1)
Common Shares Repurchased (1)
April 1, 2025 - April 30, 2025
1,137
3.74
n/a
May 1, 2025 - May 31, 2025
June 1, 2025 - June 30, 2025
ITEM 3.DEFAULTS UPON SENIOR SECURITIES.
None.
ITEM 4.MINE SAFETY DISCLOSURES.
Not applicable.
ITEM 5.OTHER INFORMATION.
ITEM 6.EXHIBITS.
ExhibitNumber
Description
2.1
Agreement and Plan of Merger, dated January 14, 2025, by and among Amplify Energy Corp., Amplify DJ Operating LLC, Alpha PRB Operating LLC, North Peak Oil & Gas, LLC, Century Oil and Gas Sub-Holdings, LLC, Juniper Capital Advisors, L.P. and the Specified Company Entities signatories thereto (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-35512) filed on January 15, 2025).
2.2
Amendment No.1 to Agreement and Plan of Merger, dated as of April 14, 2025, by and among Amplify Energy Corp., Amplify Operating LLC, Amplify PRB Operating LLC, North Peak Oil & Gas, LLC, Century Oil and Gas Sub-Holdings, LLC, Juniper Capital Advisors, L.P. and the Specified Company Entities signatories thereto (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-35512) filed on April 15, 2025).
2.3+
Purchase and Sale Agreement, dated July 1, 2025, by and between Amplify Energy Operating LLC and Murphy Exploration & Production Company – USA (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on July 1, 2025).
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
Monitoring and Oversight Agreement, dated January 14, 2025, by and between Amplify Energy Corp. and Juniper Capital Advisors, L.P. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on January 15, 2025).
10.2
Termination Agreement, dated as of April 25, 2025, by and among Amplify Energy Corp., Amplify DJ Operating LLC, Amplify PRB Operating LLC, North Peak Oil & Gas, LLC, Century Oil and Gas Sub-Holdings, LLC, Juniper Capital Advisors, L.P. and the Specified Company Entities signatories thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-35512) filed on April 25, 2025).
10.3
Cooperation Agreement, dated as of May 16, 2025, by and among Amplify Energy Corp., Clint Coghill, Stoney Lonesome HF LP and The Drake Helix Holdings, LLC (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on May 19, 2025).
10.4*
Transition and Separation Agreement, dated as of July 22, 2025, by and among Martyn Willsher, Amplify Energy Corp. and Amplify Energy Services LLC.
10.5*
PRSU Award Agreement, dated as of July 22, 2025, by and between Daniel Furbee and Amplify Energy Corp.
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.
+
Certain schedules and exhibits to this agreement have been omitted in accordance with Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the Securities and Exchange Commission on request.
46
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.
(Registrant)
Date:
August 6, 2025
By:
/s/ James Frew
Name:
James Frew
Title:
President and Chief Financial Officer
/s/ Eric Dulany
Eric Dulany
Vice President and Chief Accounting Officer