Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following is management's discussion and analysis of the significant factors that affected the Company's financial position and results of operations during the periods included in the accompanying unaudited consolidated financial statements. You should read this in conjunction with the discussion under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited consolidated financial statements included in our Annual Report on Form 10-K (as amended) for the year ended December 31, 2024, and the unaudited consolidated financial statements included in this quarterly Report.

Certain abbreviations and oil and gas industry terms used throughout this Quarterly Report are described and defined in greater detail under "Glossary of Oil And Natural Gas Terms" on page 5 of our Annual Report on Form 10-K/A (Amendment No. 3) for the year ended December 31, 2024, filed with the Securities and Exchange Commission on October 31, 2025.

Our fiscal year ends on December 31st. Interim results are presented on a quarterly basis for the quarters ended March 31st, June 30th, and September 30th, the first quarter, second quarter and third quarter, respectively, with the quarter ending December 31st being referenced herein as our fourth quarter. Fiscal 2025 means the year ended December 31, 2025, whereas fiscal 2024 means the year ended December 31, 2024.

Certain capitalized terms used below but not otherwise defined, are defined in, and shall be read along with the meanings given to such terms in, the notes to the unaudited consolidated financial statements of the Company for the three and nine months ended September 30, 2025, above.

Unless the context requires otherwise, references to the "Company," "we," "us," "our," "PEDEVCO" and "PEDEVCO Corp." refer specifically to PEDEVCO Corp. and its wholly and majority-owned subsidiaries.

In addition, unless the context otherwise requires and for the purposes of this Report only:

	·	"Boe" refers to barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids, to six Mcf of natural gas;
	·	"Bopd" refers to barrels of oil day;
	·	"Mcf" refers to a thousand cubic feet of natural gas;
	·	"NGL" refers to natural gas liquids;
	·	"Exchange Act" refers to the Securities Exchange Act of 1934, as amended;
	·	"SEC" or the "Commission" refers to the United States Securities and Exchange Commission;
	·	"SWD" means a saltwater disposal well; and
	·	"Securities Act" refers to the Securities Act of 1933, as amended.

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Available Information

The Company's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Exchange Act, are filed with the SEC. The Company is subject to the informational requirements of the Exchange Act and files or furnishes reports, proxy statements and other information with the SEC. Such reports and other information filed by the Company with the SEC are available free of charge at our website (www.pedevco.com) under "Investors" - "SEC Filings", when such reports are available on the SEC's website. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. The Company periodically provides other information for investors on its corporate website, www.pedevco.com. This includes press releases and other information about financial performance, information on corporate governance and details related to the Company's annual meeting of shareholders. The information contained on the websites referenced in this Form 10-Q is not incorporated by reference into this filing. Further, the Company's references to website URLs are intended to be inactive textual references only.

Summary of The Information Contained in Management's Discussion and Analysis of Financial Condition and Results of Operations

Our Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is provided in addition to the accompanying consolidated financial statements and notes to assist readers in understanding our results of operations, financial condition, and cash flows. Our MD&A is organized as follows:

	·	General Overview. Discussion of our business and overall analysis of financial and other highlights affecting us, to provide context for the remainder of our MD&A.
	·	Strategy. Discussion of our strategy moving forward and how we plan to seek to increase stockholder value.
	·	Results of Operations and Financial Condition. An analysis of our financial results comparing the three and nine-month periods ended September 30, 2025, and 2024, and a discussion of changes in our consolidated balance sheets, cash flows and a discussion of our financial condition.
	·	Critical Accounting Estimates. Accounting estimates that we believe are important to understanding the assumptions and judgments incorporated in our reported financial results and forecasts.

General Overview

We are an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies. Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the "Permian Basin") and in the Denver-Julesberg Basin ("D-J Basin") in Colorado and Wyoming. As of September 30, 2025, we held approximately 14,105 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, Pacific Energy Development Corp. ("PEDCO"), and which are operated by our wholly-owned operating subsidiary, Ridgeway Arizona Oil Corp. ("RAZO"), which asset we refer to as our "Permian Basin Asset." Also as of September 30, 2025, we held approximately 18,489 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, through our wholly-owned subsidiary, PRH Holdings LLC ("PRH"), and which are operated by our wholly-owned operating subsidiary, Red Hawk Petroleum, LLC ("Red Hawk"), which asset we refer to as our "D-J Basin Asset." As of September 30, 2025, we held interests in 40 gross (34.5 net) wells in our Permian Basin Asset, of which 31 gross (22.1 net) wells are active producers, two are active injectors and two are active salt water disposal wells, all of which were held by PEDCO and operated by RAZO, and interests in 52 gross (5.7 net) wells in our D-J Basin Asset held by PRH, and 17 wells that had an after-payout interest. On April 3, 2025, and effective January 1, 2025, in order to reduce plugging and abandonment liabilities and recurring operational expenses, the Company sold all of its legacy 17 gross (15.4 net) operated wells in its D-J Basin Asset, with the Company retaining ownership in all its existing leasehold, which legacy wells no longer provided meaningful oil and gas production to the Company.

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As discussed in greater detail above in "Part I - Financial Information-Item 1. Financial Statements-Note 15 - Subsequent Events", on October 31, 2025 (the "Closing Date"), the Company closed the transactions contemplated by an Agreement and Plan of Merger dated October 31, 2025 (the "Merger Agreement"), between the Company, NP Merger Sub, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company ("First Merger Sub"), COG Merger Sub, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company ("Second Merger Sub," and together with First Merger Sub, the "Merger Subs"), 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 purposes of the specified provisions therein, North Peak Oil & Gas Holdings, LLC, a Delaware limited partnership ("North Peak").

Pursuant to the Merger Agreement, (a) First Merger Sub merged with and into NPOG, with NPOG being the surviving entity and a wholly-owned subsidiary of PEDEVCO and (b) Second Merger Sub merged with and into COG, with COG being the surviving entity and a wholly-owned subsidiary of PEDEVCO (the "Mergers").

Because the Mergers closed on October 31, 2025, after the period covered by this Report, the operations, assets, liabilities and other financial information of the Acquired Companies are not included in the financial statements included herein.

The Acquired Companies own substantial oil-weighted producing assets and significant leasehold interest in the D-J Basin and Powder River Basin located in Wyoming (the "Powder River Basins").

Highlights of the Combined Company

	·	Positions PEDEVCO as a Premier Publicly-Traded Rockies-Focused Operator: The addition of substantial, oil-weighted, production and a large acreage position across the Northern DJ Basin and Powder River Basin ("PRB"), together with PEDEVCO's existing DJ Basin production and acreage, transforms PEDEVCO into a premier publicly-traded Rockies-focused operator with approximately 320,000 net acres.
	·	Strong Cash Generation with Extensive Potential Drilling Inventory: The combined company generates significant cash flow, supported by its relatively high percentage oil production and competitive cost structure. With its large acreage position in the DJ Basin and Powder River Basin, combined with the multiple formations being developed in such areas, the Company has identified well over a decade of potential future drilling inventory on its existing position.
	·	Low-Cost Operator and Conservative Capital Structure: PEDEVCO remains a low-cost operator with low general and administrative expenses (G&A) and a conservative capital structure, which it expects to maintain in the future.
	·	Positioned for Organic Growth and Strategic Consolidation: PEDEVCO has thirty-two wells of varying working interest that have recently been completed or are scheduled to be completed in Q4 2025 and early Q1 2026, which are expected to generate material production growth for the Company over the next several months. Additionally, the Company plans to focus on strategic consolidation in its areas of focus with potential acquisitions possible, with the goal of delivering accretion and operational synergies to the benefit of shareholders, while maintaining a healthy capital structure.

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Strategy

We believe that horizontal development and exploitation of conventional and unconventional oil and gas assets in the Rockies region including the D-J and Powder River Basins, represent among the most economic oil and natural gas plays in the U.S. We plan to optimize our existing assets and opportunistically seek additional acreage proximate to our currently held core acreage, as well as target other acquisitions in the Rockies region that fit our acquisition criteria. We believe there is a significant opportunity to build a leading oil and gas company in the Rockies region through both organic growth and acquisitions on terms that are more attractive than what we see in other oil and gas producing basins.

Specifically, we seek to increase stockholder value through the following strategies:

·	Grow production, cash flow and reserves by developing our operated drilling inventory and participating opportunistically in non-operated projects. We believe our extensive inventory of drilling locations in the D-J Basin, Powder River Basin, and Permian Basin, combined with our operating expertise, will enable us to continue to deliver accretive production, cash flow and reserves growth. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs, will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base.
·	Apply modern drilling and completion techniques and technologies. We own and intend to acquire additional properties that have been historically underdeveloped and underexploited. We believe our attention to detail and application of the latest industry advances in horizontal drilling, completions design, frac intensity and locally optimal frac fluids will allow us to successfully develop our properties.
·	Optimization of well density and configuration. We own properties that are legacy oil fields characterized by widespread vertical and horizontal development and geological well control. We utilize the extensive geological, petrophysical and production data of such legacy properties to confirm optimal well spacing and configuration using modern reservoir evaluation methodologies.
·	Maintain a high degree of operational control and/or form partnerships which allow for a high degree of control over non-operated properties. We believe that by retaining operational control and/or by forming partnerships which require consent and input by all partners in major development projects, we can efficiently manage the timing and amount of our capital expenditures and operating costs, and thus key in on the optimal drilling and completions strategies, which we believe will generate higher recoveries and greater rates of return per well.
·	Leverage extensive deal flow, technical and operational experience to evaluate and execute accretive acquisition opportunities. Our management and technical teams have an extensive track record of forming and building oil and gas businesses. We also have significant expertise in successfully sourcing, evaluating and executing acquisition opportunities. We believe our understanding of the geology, geophysics and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acreage in order to grow our reserve base and maximize stockholder value.
·	Preserve financial flexibility to pursue organic and external growth opportunities. We intend to maintain a disciplined financial profile in order to provide flexibility across various commodity and market cycles.

Our strategy is to be the operator and/or a significant working interest owner, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan. In areas we deem highly economic and do not have a high enough working interest to serve as operator, we seek to participate in projects if returns match or exceed other projects in our portfolio. Due to the fragmented nature of acreage positions in some of our holdings our ownership interest does not always allow for us to serve as operator. Our net capital expenditures for 2025 are estimated at the time of this filing to range between $42 million to $45 million. This estimate includes a range of $40 million to $43.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets (of which we have incurred approximately $16.7 million through September 30, 2025) and approximately $1.5 million in estimated capital expenditures for electronic submersible pump (ESP) purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses (of which we have incurred approximately $0.5 million through September 30, 2025) . Approximately $5.7 million of capital was added to the 2025 budget after the closing of the Mergers. We anticipate that approximately 78% to 80% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and Area of Mutual Interest ("AMI") entered into in August 2024 with a private operator discussed below, and the Mergers. These estimates do not include expenditures for acquisitions or other projects that may arise but are not currently anticipated. We periodically review our capital expenditures and adjust our capital forecasts and allocations based on liquidity, drilling results, leasehold acquisition opportunities, partner non-consents, proposals from third party operators, and commodity prices, while prioritizing our financial strength and liquidity.

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We plan to continue to evaluate D-J Basin well proposals as received from third party operators and participate in those we deem most economic and prospective. If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and nearly all held by production ("HBP"), allowing for flexibility of timing on development. Our 2025 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity.

We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund the remainder of our 2025 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) public or private debt or equity financings, including up to $7.6 million in securities which we may sell in the future in "at the market offerings", pursuant to a Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the "Lead Agent"), and A.G.P./Alliance Global Partners ("AGP" and, together with the Lead Agent, the "Agents")(discussed in greater detail below under "Liquidity and Capital Resources-Financing" (under which we have sold 489,967 shares to date), and (iv) funding through credit or loan facilities, including under the Company's reserve-based lending facility ("RBL") with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $120 million and an aggregate maximum revolving credit amount of $250 million (of which $87 million has been drawn down by the Company to date), as discussed in greater detail below under "Liquidity and Capital Resources". In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2025.

Participations Agreements Related to D-J Basin Assets

On August 21, 2024, the Company, through PRH, entered into a five-year Participation Agreement with a large private equity-backed D-J Basin exploration and production company with extensive operational experience ("Joint Development Party"), whereby the Joint Development Party assigned to PRH a 30% interest in approximately 7,607 net acres of existing oil and gas leases and PRH assigned to the Joint Development Party a 70% interest in approximately 3,166 net acres of oil and gas leases, all located within the SW Pony Prospect in the D-J Basin in Weld County, Colorado. Additionally, to facilitate joint development of the SW Pony Prospect, the parties agreed to an approximately 16,900 gross acre Area of Mutual Interest wherein the Joint Development Party will transfer 30% of future interests acquired by the Joint Development Party in leaseholds to PRH, and PRH will transfer 70% of future interests acquired by PRH in leaseholds to the Joint Development Party, in each case at an acquisition cost proportionate to their respective interests. The assigned interests will be subject to an overriding royalty, such that the assigning party shall deliver to the other party leasehold interests with an 80% net revenue interest, and the parties agreed that the Joint Development Party will be the operator of the combined leaseholds. The Participation Agreement specifically addresses the Harlequin Wells, which are existing wells within the SW Pony Prospect, whereby PRH acquired a 30% undivided interest in six Harlequin Wells as part of the leasehold assignment. The Company correspondingly paid $8.6 million in capital costs related to these wells.

In February 2025, the Company entered into a joint development agreement ("Agreement") with a large, Denver, Colorado-based private equity-backed D-J Basin E&P Company with extensive operational experience ("Operator"), pursuant to which the parties agreed to jointly participate in the expansion and development of the Company's Roth and Amber DSUs located in Weld County, Colorado, with the Operator paying to the Company $1.7 million, the Company agreeing to amend the Company's existing Roth and Amber DSUs to increase each to 1,600 acres and transferring operatorship of the DSUs to the Operator, and the parties agreeing to jointly participate in the development of the Roth and Amber DSUs.

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Merger Agreement

As discussed above, on October 31, 2025, we closed the transactions contemplated by the Merger Agreement and consummated the Mergers.

PIPE Offering

Concurrently with the Closing of the Mergers, certain investors (the "PIPE Investors") subscribed for and purchased an aggregate of 6,363,637 shares of PEDEVCO Series A Preferred Stock (the "PIPE Preferred Shares"), at a price per share equal to $5.50 per share (the "Purchase Price"), pursuant to their entry into Series A Convertible Preferred Stock Subscription Agreements in favor of the Company (the "Subscription Agreements"). When converted in full, the PIPE Preferred Shares will convert into 63,636,370 shares of PEDEVCO common stock (the "PIPE Conversion Shares").

The PIPE Investors included (a) The SGK 2018 Revocable Trust, a family trust of which Dr. Simon Kukes, the then Executive Chairman of PEDEVCO is trustee and beneficiary ($15,409,977); (b) American Resources, Inc., an entity partially owned and controlled by J. Douglas Schick, the Chief Executive Officer, President and member of the Board ($250,003); (c) Clark R. Moore, the Executive Vice President, General Counsel and Secretary of PEDEVCO ($25,003); (d) John J. Scelfo Revocable Trust Dated October 8, 2003, a trust of which John J. Scelfo, a member of the Board, is trustee and beneficiary ($550,000); (f) Jody D. Crook, the Chief Commercial Officer of PEDEVCO ($25,003); (g) J PED, LLC, an entity affiliated with Juniper Capital Advisors, L.P. ("Juniper") ($18,550,004); (h) Reagan T. Dukes, the then Chief Executive Officer of the Acquired Companies, who was appointed Chief Operating Officer of PEDEVCO at the Closing ($52,503) and (i) Robert J. Long, the then Chief Financial Officer of the Acquired Companies, who was appointed Chief Financial Officer, Treasurer and Principal Accounting/Financial Officer of PEDEVCO at the Closing ($52,503). The PIPE Financing closed concurrently with the Mergers and the $35,000,004 of net proceeds raised by the Company pursuant to the PIPE Financing was used to pay off certain liabilities of the Acquired Companies in connection with the Mergers and certain expenses of the PIPE Financing and Mergers.

Second Amended and Restated Designation of Series A Convertible Preferred Stock

In preparation for the Closing, the Board of Directors approved the Second Amended and Restated Certificate of Designations establishing the rights, preferences, and limitations of PEDEVCO's Series A Convertible Preferred Stock (the "Series A Preferred Stock") on October 29, 2025, which was filed with the Texas Secretary of State on October 31, 2025. A total of 17,013,637 shares of Series A Preferred Stock were designated. Except as required by law or the designation, Series A Preferred Stock holders have no voting rights, except the right to elect one director (the "Series A Director") until the Automatic Conversion Date, with Josh Schmidt serving as the initial director.

Holders of Series A Preferred Stock are entitled to certain protective provisions, requiring approval by a majority in interest of outstanding shares for actions such as amending governing documents, changing board composition, issuing new securities, major acquisitions or disposals, indebtedness above $500,000, executive appointments, and other material corporate actions. The holders of Series A Preferred Stock are provided no dividend rights, and in the event of liquidation, dissolution, or winding-up, Series A holders receive distributions pari passu with common shareholders, as if their shares were converted to common stock. The Series A Preferred Stock converts into PEDEVCO common stock automatically on the Automatic Conversion Date in a ratio of 10-for-1, subject to standard adjustments for splits, dividends, or recapitalizations.

How We Conduct Our Business and Evaluate Our Operations

Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe had significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.

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We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

	·	production volumes;
	·	realized prices on the sale of oil and natural gas, including the effects of our commodity derivative contracts;
	·	oil and natural gas production and operating expenses;
	·	capital expenditures;
	·	general and administrative expenses;
	·	net cash provided by operating activities; and
	·	net income.

Results of Operations and Financial Condition

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by, among other factors, weather conditions, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our production volumes or revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. We expect prices to remain volatile for the remainder of the year. For information about the impact of realized commodity prices on our natural gas and crude oil and condensate revenues, refer to "Results of Operations" below.

Results of Operations

The following discussion and analysis of the results of operations for the three-month and nine-month periods ended September 30, 2025, and 2024, should be read in conjunction with our consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. The majority of the numbers presented below are rounded numbers and should be considered as approximate.

Three Months Ended September 30, 2025, vs. Three Months Ended September 30, 2024

We reported a net loss for the three-month period ended September 30, 2025, of $0.3 million, or ($0.00) per common share, compared to net income for the three-month period ended September 30, 2024 of $2.9 million or $0.03 per share. The decrease in net income of $3.2 million, when comparing the current period to the prior year's period, was primarily due to a $0.8 million increase in total operating expense (which includes an impairment of oil and gas properties of $0.2 million), coupled with a decrease of revenues of $2.1 million and a $0.7 million gain in sale of oil and gas properties in the prior period offset with $0.2 million increased in other income (each discussed in more detail below) and an income tax benefit of $0.2 million (see Note 13 - Income Taxes, in the notes to the consolidated financial statements above under "Part I - Financial Information-Item 1. Financial Statements").

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Net Revenues

The following table sets forth the operating results and production data for the periods indicated:

		Three Months Ended
		September 30,								Increase				% Increase
		2025				2024				(Decrease)				(Decrease)
Sale Volumes:
Crude Oil (Bbls)			96,864				108,810				(11,946	)		(11%)
Natural Gas (Mcf)			128,369				142,669				(14,300	)		(10%)
NGL (Bbls)			17,007				23,508				(6,501	)		(28%)
Total (Boe) (1)			135,266				156,096				(20,830	)		(13%)
Crude Oil (Bbls per day)			1,053				1,183				(130	)		(11%)
Natural Gas (Mcf per day)			1,395				1,551				(156	)		(10%)
NGL (Bbls per day)			185				256				(71	)		(28%)
Total (Boe per day) (1)			1,471				1,698				(227	)		(13%)
Average Sale Price:
Crude Oil ($/Bbl)		$	63.76			$	75.82			$	(12.06	)		(16%)
Natural Gas ($/Mcf)			2.94				1.23				1.71				139%
NGL ($/Bbl)			24.00				26.53				(2.53	)		(10%)
Net Operating Revenues (in thousands):
Crude Oil		$	6,176			$	8,250			$	(2,074	)		(25%)
Natural Gas			377				176				201				114%
NGL			408				624				(216	)		(35%)
Total Revenues		$	6,961			$	9,050			$	(2,089	)		(23%)

(1)	Assumes 6 Mcf of natural gas equivalents to one barrel of oil.

Total crude oil, natural gas and NGL revenues for the three-month period ended September 30, 2025, decreased $2.1 million, or 23%, to $7.0 million, compared to $9.1 million for the same period a year ago, due to an unfavorable price variance of $1.1 million, due to the average sales price for crude oil and NGL realized by the Company decreasing compared to the three-month period ended September 30, 2024, coupled with an unfavorable volume variance of $1.0 million. Production volume decreased mainly due to the sale of 17 operated wells in the D-J Basin in April 2025, and natural declines from both our third-party D-J Basin wells and our Permian Basin wells along with our drilling partner, which were completed last period and initially produced at much higher rates.

Operating Expenses and Other Income

The following table summarizes our production costs and operating expenses for the periods indicated (in thousands):

		Three Months Ended
		September 30,								Increase				% Increase
		2025				2024				(Decrease)				(Decrease)
Direct Lease Operating Expenses		$	1,181			$	1,603			$	(422	)		(26%)
Workovers			-				124				(124	)		(100%)
Other*			914				829				85				10%
Total Lease Operating Expenses		$	2,095			$	2,556			$	(461	)		(18%)
Depreciation, Depletion,
Amortization and Accretion		$	4,010			$	3,055			$	955				31%
Impairment of Oil and Gas Properties		$	165			$	-			$	165				100%
General and Administrative (Cash)		$	988			$	879			$	109				12%
Share-Based Compensation (Non-Cash)			537				464				73				16%
Total General and Administrative Expense		$	1,525			$	1,343			$	182				14%
Gain on Sale of Oil and Gas Properties		$	-			$	735			$	(735	)			100%
Interest Expense		$	102			$	-			$	102				100%
Interest Income		$	69			$	84			$	(15	)		(18%)
Other Income		$	378			$	-			$	378				100%

* Includes severance, ad valorem taxes, assessment and gathering, transportation and processing costs.

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Lease Operating Expenses. The decrease of $0.5 million was primarily due to lower direct and variable lease operating expenses associated with the lower crude oil, natural gas and NGL volumes resulting from the production volume declines noted above.

Depreciation, Depletion, Amortization and Accretion. The $1.0 million increase was primarily the result of additional capital spending related to lift conversions on five operated wells in our Permian Basin Asset and additional accretion expenses from our increased ARO liability from our compliance order with the New Mexico OCD.

Impairment of Oil and Gas Properties. The Company recorded an impairment of oil and gas properties of $0.2 million related to undeveloped leases representing 187 net acres in the D-J Basin that it allowed to expire or currently have no plans to drill prior to expiration, in the current period. There was no impairment in the prior period.

General and Administrative Expenses (excluding share-based compensation). The $0.1 million increase was primarily the result of additional payroll, audit fees and software licensing fees.

Share-Based Compensation. Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, increased nominally due to the award of certain employee restricted stock and stock-based options. Share-based compensation is utilized for the purpose of conserving cash resources for use in field development activities and operations.

Gain on Sale of Oil and Gas Properties. The Company sold leasehold rights to 320 net acres located in the D-J Basin for net cash proceeds of $0.7 million and recognized a gain on sale of oil and gas properties of $0.7 million in the prior period. We had no sales of oil and gas properties during the current period.

Interest expense. Primarily relates to the amortization of deferred financing costs related to our RBL credit facility in the current period compared to no amortization cost in the prior period.

Interest Income and Other Income. Includes interest earned from our interest-bearing cash accounts and interest on our note receivable (in the prior period), which nominally decreased due to additional cash usage for our operations and no interest on the note receivable, which has been fully written-off. Other income in the current period is related to revenue and tax adjustments from a prior period from a third-party operating partner.

Nine Months Ended September 30, 2025 vs. Nine Months Ended September 30, 2024

We reported a net loss for the nine-month period ended September 30, 2025 of $1.9 million, or ($0.02) per share, compared to net income for the nine-month period ended September 30, 2024 of $6.4 million or $0.07 per share. The decrease in net income of $8.2 million, when comparing the current period to the prior year's period, was primarily due to the recognition of $1.4 million from a note receivable - credit loss related to the full write-off of the Tilloo Note receivable, corresponding accrued interest and posting closing adjustments owed to the Company related to the sale of our EOR subsidiary and other reductions to operating income of 7.9 million (a $6.3 million reduction in revenue, and a $0.9 million impairment to oil and gas properties and a $0.7 million of other operating expenses), offset by a net $0.3 million gain on sale on oil and gas properties when comparing periods and a $0.2 million increase in other income (each discussed in more detail below) and an income tax benefit of $0.6 million (see Note 13 - Income Taxes, in the notes to the consolidated financial statements above under "Part I - Financial Information-Item 1. Financial Statements").

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Net Revenues

The following table sets forth the operating results and production data for the periods indicated:

		Nine Months Ended
		September 30,								Increase				% Increase
		2025				2024				(Decrease)				(Decrease)
Sale Volumes:
Crude Oil (Bbls)			299,795				349,185				(49,390	)		(14%)
Natural Gas (Mcf)			414,596				420,182				(5,586	)		(1%)
NGL (Bbls)			58,013				54,148				3,865				7%
Total (Boe) (1)			426,907				473,363				(46,546	)		(10%)
Crude Oil (Bbls per day)			1,098				1,274				(176	)		(14%)
Natural Gas (Mcf per day)			1,519				1,534				(15	)			(1%)
NGL (Bbls per day)			213				198				15				8%
Total (Boe per day) (1)			1,564				1,728				(164	)			(9%)
Average Sale Price:
Crude Oil ($/Bbl)		$	64.81			$	76.34			$	(11.53	)		(15%)
Natural Gas ($/Mcf)			3.72				1.90				1.82				96%
NGL ($/Bbl)			29.25				28.11				1.14				4%
Net Operating Revenues (in thousands):
Crude Oil		$	19,430			$	26,656			$	(7,226	)		(27%)
Natural Gas			1,542				799				743				93%
NGL			1,697				1,522				175				11%
Total Revenues		$	22,669			$	28,977			$	(6,308	)		(22%)

(1)	Assumes 6 Mcf of natural gas equivalents to one barrel of oil.

Total crude oil, natural gas and NGL revenues for the nine-month period ended September 30, 2025, decreased $6.3 million, or 22%, to $22.7 million, compared to $29.0 million for the same period a year ago due to an unfavorable price variance of $3.2 million, due to the average sales price for crude oil realized by the Company decreasing compared to the nine-month period ended September 30, 2024, coupled with an unfavorable volume variance of $3.1 million. Production volume decreased mainly due to the sale of 17 operated wells in the D-J Basin in April 2025, and natural declines from both our third-party D-J Basin wells and our Permian Basin wells along with our drilling partner, which were completed last period and initially produced at much higher rates.

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Operating Expenses and Other Income (Expense)

The following table summarizes our production costs and operating expenses for the periods indicated (in thousands):

		Nine Months Ended
		September 30,								Increase				% Increase
		2025				2024				(Decrease)				(Decrease)
Direct Lease Operating Expenses		$	4,362			$	4,670			$	(308	)		(7%)
Workovers			709				859				(150	)		(17%)
Other*			3,234				3,106				128				4%
Total Lease Operating Expenses		$	8,305			$	8,635			$	(330	)		(4%)
Depreciation, Depletion,
Amortization and Accretion		$	11,213			$	10,782			$	431				4%
Impairment of Oil and Gas Properties		$	907			$	-			$	907				100%
General and Administrative (Cash)		$	3,329			$	2,820			$	509				18%
Share-Based Compensation (Non-Cash)			1,486				1,401				85				6%
Total General and Administrative Expense		$	4,815			$	4,221			$	594				14%
Gain on Sale of Oil and Gas Properties		$	1,021			$	735			$	286				39%
Gain on Sale of Fixed Asset		$	-			$	12			$	(12	)		(100%)
Note receivable - Credit Loss		$	1,378			$	-			$	1,378				100%
Interest Expense		$	102			$	-			$	102				100%
Interest Income		$	196			$	326			$	(130	)		(40%)
Other Income (Expense)		$	395			$	(43	)		$	438				1,019%

*Includes severance, ad valorem taxes, assessment and gathering, transportation and processing costs.

Lease Operating Expenses. The decrease of $0.3 million was primarily due to lower direct and variable lease operating expenses associated with the lower crude oil, natural gas and NGL volumes resulting from the production volume declines noted above.

Depreciation, Depletion, Amortization and Accretion. The $0.4 million increase was primarily the result of additional capital spending related to lift conversions on five operated wells in our Permian Basin Asset and additional accretion expenses from our increased ARO liability from our compliance order with the New Mexico OCD.

Impairment of Oil and Gas Properties. The Company recorded an impairment of oil and gas properties of $0.9 million related to undeveloped leases representing 1,034 net acres in the D-J Basin that it allowed to expire or currently have no plans to drill prior to expiration, in the current period. There was no impairment in the prior period.

General and Administrative Expenses (excluding share-based compensation). The $0.5 million increase was primarily the result of additional payroll, audit fees and software licensing fees.

Share-Based Compensation. Share-based compensation, which is included in general and administrative expenses in the Statements of Operations, increased nominally due to the award of certain employee restricted stock and stock-based options. Share-based compensation is utilized for the purpose of conserving cash resources for use in field development activities and operations.

Gain on Sale of Oil and Gas Properties. Gain on sale of oil and gas properties related to the Company's sale of all of its legacy 17 gross (15.4 net) operated wells in its D-J Basin Asset, while the Company sold leasehold rights to 320 net acres located in the D-J Basin for net cash proceeds of $0.7 million and recognized a gain on sale of oil and gas properties of $0.7 million during the prior period

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Gain on Sale of Fixed Asset. Relates to the sale of a vehicle and the subsequent purchase of another vehicle in the prior period. We had no sales of fixed assets during the current period.

Note receivable - credit loss. Represents the full write-off our note receivable and accrued interest as well as a post-closing adjustments receivable related to the sale of our then wholly-owned subsidiary EOR Operating Company in November 2023.

Interest expense. Primarily relates to the amortization of deferred financing costs related to our RBL credit facility in the current period compared to no amortization cost in the prior period.

Interest Income and Other Income (Expense). Includes interest earned from our interest-bearing cash accounts and interest on our note receivable, which nominally decreased due to additional cash usage for our operations and no interest on the note receivable, which has been fully written-off in the current period. Other income in the current period is related to sales tax refunds and other expense in the prior period primarily relates to the subsequent disposition of a cash escrow bank balance related to the sale of our former wholly-owned subsidiary EOR Operating Company.

Liquidity and Capital Resources

The primary sources of cash for the Company during the nine-month period ended September 30, 2025 were from $22.7 million in sales of crude oil, natural gas and NGLs. The primary uses of cash were funds used for drilling, completion and operating costs.

Working Capital

At September 30, 2025, the Company's total current assets of $16.1 million exceeded its total current liabilities of $14.6 million, resulting in a working capital surplus of $1.5 million, while at December 31, 2024, the Company's total current assets of $13.2 million exceeded its total current liabilities of $6.9 million, resulting in a working capital surplus of $6.3 million. The $4.8 million decrease in our working capital surplus is primarily related to an increase in payables and expenses related to our current capital drilling program, when comparing the current period to the prior period (described above).

Financing

The Company has an ongoing $8.0 million offering of securities in an "at the market offering", pursuant to which the Company may sell securities from time to time (the "ATM Offering"). During the month of June 2025, the Company sold an aggregate of 489,967 shares of common stock in five separate sales at a sales prices ranging between $0.716 to $0.801 per share via an ongoing "at the market offering" (for net proceeds of $354,000, which includes $11,000 in commission fees. The Company also incurred $214,000 in initial and subsequent legal and audit-related fees and expenses incurred in connection with the registration and placement of the ATM Offering. As of September 30, 2025, a total of $7.6 million is available for future sales of common stock under the ATM Offering.

The ATM Offering was made pursuant to the terms of that certain December 20, 2024, Sales Agreement (the "Sales Agreement"), entered into with Roth Capital Partners, LLC (the "Lead Agent") and A.G.P./Alliance Global Partners ("AGP", and collectively with the Lead Agent, the "Agents"), pursuant to which the Company may sell securities from time to time in an "at the market offering" (the "ATM Offering"). The Company will pay the Lead Agent a commission of 3.0% of the gross sales price of any shares sold under the Sales Agreement. The Company also agreed to reimburse the Agents for their reasonable and documented out-of-pocket expenses in an amount not to exceed $75,000, in connection with entering into the Sales Agreement and for the Agents' reasonable and documented out-of-pocket expenses related to quarterly maintenance of the Sales Agreement on a quarterly basis in an amount not to exceed $5,000.

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We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund the remaining portion of our 2025 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) borrowing under our reserve-based lending facility with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $120 million and an aggregate maximum revolving credit amount of $250 million (of which $87 million has been drawn down by the Company to date to fund the Juniper merger), as discussed below, (iv) public or private debt or equity financings, pursuant to the ATM Offering noted above, and (v) funding through other credit or loan facilities. In addition, we may seek additional funding through asset sales, farm-out arrangements, and partnerships to fund potential acquisitions during the remainder of 2025.

On October 31, 2025, the Company entered into an Amended and Restated Credit Agreement (the "A&R Credit Agreement"), which amended and restated that prior senior secured revolving credit agreement entered into on September 11, 2024 (the "Original Credit Agreement") among the Company, as borrower, Citibank, N.A., as administrative agent (the "Administrative Agent"), and the lenders from time to time party thereto (the "Lenders"). The A&R Credit Agreement has a maturity date of October 31, 2029. The A&R Credit Agreement provides for an initial borrowing base and aggregate elected commitments of $120 million and an aggregate maximum revolving credit amount of $250 million. The Company has drawn down $87 million under the Facility as of the filing date of this Report. The A&R Credit Agreement includes customary representations and warranties, and affirmative and negative covenants of the Company for a facility of that size and type, including prohibiting the Company from creating any indebtedness without the consent of the Lenders, subject to certain exceptions, and the maintenance of the following financial ratios: (i) a current ratio, which is the ratio of the Company's consolidated current assets (including unused commitments under the A&R Credit Agreement and excluding non- cash derivative assets) to its consolidated current liabilities (excluding the current portion of long-term debt under the A&R Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and (ii) a leverage ratio, which is the ratio of Total Net Debt to EBITDAX (each as defined in the A&R Credit Agreement) for the prior four fiscal quarters, of not greater than 3.0 to 1.0. The Company is required to hedge at least 75% of its projected proved developed producing reserves (PDP) oil and gas production at the time of entry into the A&R Credit Agreement, for the first 24 months of the agreement, and 50% of its projected PDP of oil and gas production for months 25-36. Afterward, within 60 days after each fiscal quarter, the Company must show it has hedged at least 50% of expected oil and gas production for the next 18 months. The Company may hedge crude oil, natural gas, or natural gas liquids (on a barrel of oil equivalent basis) to meet these requirements, but may not hedge more than 75% of anticipated production (on a barrel of oil equivalent basis) for any month.

Cash Flows (in thousands)

		Nine Months Ended September 30,
		2025				2024
Cash flows provided by operating activities		$	12,905			$	8,547
Cash flows used in investing activities			(5,982	)			(22,098	)
Cash flows provided by financing activities			139				-
Net increase (decrease) in cash and restricted cash		$	7,062			$	(13,551	)

Cash flows provided by operating activities. Net cash used in operating activities increased by $4.4 million for the current year's period, when compared to the prior year's period, primarily due to a decrease in net income of $8.2 million coupled with a $0.6 increase in deferred tax asset offset by a $0.4 million decrease in depreciation, depletion and amortization and by a $0.9 million impairment of oil and gas properties, and $1.4 million from a note receivable - credit loss , and a $1.7 million net increase to our other components of working capital (predominantly from increased expenses from our drilling and completion activities).

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Cash flows used in investing activities. Although total capital costs (accrued and cash) decreased to $17.7 million this period from $18.1 million last period (see extract table below from our Consolidated Statements of Cash Flows), net cash used in investing activities actually decreased by $16.1 million year-over-year primarily due to a decrease in cash only outlays from our capital spending relating to our drilling and completion activities offset by cash received from the sale of oil and gas properties.

		Nine Months Ended September 30,
		2025				2024
Cash paid for drilling and completion costs			(8,905	)			(23,134	)
Change in accrued oil and gas development costs			(8,843	)			5,009
Total capital costs			(17,748	)			(18,125	)

Cash flows from financing activities. Consisted of sales of our common stock via our ATM Offering in the current period (discussed above). There were no financing activities in the prior period.

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Non-GAAP Financial Measures

We have included EBITDA and Adjusted EBITDA in this Report as supplements to generally accepted accounting principles in the United States of America ("GAAP") measures of performance to provide investors with an additional financial analytical framework which management uses, in addition to historical operating results, as the basis for financial, operational and planning decisions and present measurements that third parties have indicated are useful in assessing the Company and its results of operations. "EBITDA" represents net income before interest, taxes, depreciation and amortization. "Adjusted EBITDA" represents EBITDA, less share-based compensation, impairment of oil and gas properties, gain on sale of oil and gas properties, gain on sale of fixed asset and note receivable - credit loss. Adjusted EBITDA excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDA and Adjusted EBITDA are presented because we believe they provide additional useful information to investors due to the various noncash items during the period. EBITDA and Adjusted EBITDA are also frequently used by analysts, investors and other interested parties to evaluate companies in our industry. EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: EBITDA and Adjusted EBITDA do not reflect cash expenditures, future requirements for capital expenditures, or contractual commitments; EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and EBITDA and Adjusted EBITDA do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments. For example, although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Additionally, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than PEDEVCO Corp. does, limiting its usefulness as a comparative measure. You should not consider EBITDA and Adjusted EBITDA in isolation, or as substitutes for analysis of the Company's results as reported under GAAP. The Company's presentation of these measures should not be construed as an inference that future results will be unaffected by unusual or nonrecurring items. We compensate for these limitations by providing a reconciliation of each of these non-GAAP measures to the most comparable GAAP measure. We encourage investors and others to review our business, results of operations, and financial information in their entirety, not to rely on any single financial measure, and to view these non-GAAP measures in conjunction with the most directly comparable GAAP financial measure. The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDA (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2025				2024				2025				2024
Net (loss) income		$	(325	)		$	2,915			$	(1,861	)		$	6,369
Add (deduct)
Interest expense			102				-				102				-
Income tax benefit			(164	)			-				(578	)			-
Depreciation, depletion, amortization and accretion			4,010				3,055				11,213				10,782
EBITDA			3,623				5,970				8,876				17,151
Add (deduct)
Share-based compensation			537				464				1,486				1,401
Impairment of oil and gas properties			165				-				907				-
Gain on sale of oil and gas properties			-				(735	)			(1,021	)			(735	)
Gain on sale of fixed asset			-				-				-				(12	)
Note receivable - credit loss			-				-				1,378				-
Adjusted EBITDA		$	4,325			$	5,699			$	11,626			$	17,805

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our most significant judgments and estimates used in preparation of our consolidated financial statements.

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Oil and Gas Properties, Successful Efforts Method. The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. Geological and geophysical costs are expensed when incurred. Costs of exploratory wells are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise, the related well costs are expensed as dry holes.

Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination are accounted for in accordance with the policy outlined above.

Depreciation, depletion and amortization of capitalized oil and gas properties is calculated on a field-by-field basis using the unit of production method. Lease acquisition costs are amortized over the total estimated proved developed and undeveloped reserves and all other capitalized costs are amortized over proved developed reserves. Costs specific to developmental wells for which drilling is in progress or uncompleted are capitalized as wells in progress and not subject to amortization until completion and production commences, at which time amortization on the basis of production will begin.

Revenue Recognition. The Company's revenue is comprised entirely of revenue from exploration and production activities. The Company's oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

Contracts with customers have varying terms, including month-to-month contracts, and contracts with a finite term. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

Revenues are recognized for the sale of the Company's net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.

Stock-Based Compensation. Pursuant to the provisions of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 718, Compensation - Stock Compensation, which establishes accounting for equity instruments exchanged for employee service, we utilize the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances. We estimate volatility by considering historical stock volatility. We have opted to use the simplified method for estimating expected term, which is equal to the midpoint between the vesting period and the contractual term.

Recently Adopted and Recently Issued Accounting Pronouncements.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity's effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures. This ASU will be effective for the annual period ending December 31, 2025. The Company is currently evaluating the timing and impacts of adoption of this ASU.

In November 2024, the FASB issued ASU 2024-03, "Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses," which requires additional disclosure about specified categories of expenses included in relevant expense captions presented on the income statement. The amendments are effective for annual periods beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively. The Company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

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