PEDEVCO (PED) Q2 2025 10-Q: $1.38M Bad Debt, Controls Weakness

Q: How large was the note receivable credit loss recognized by PEDEVCO in Q2 2025?

PEDEVCO recognized a total $1,378,000 in note receivable credit loss for the three and six months ended June 30, 2025, which includes write-offs of post-closing adjustments.

Q: What noncash compensation did the company record in the period?

The company granted 1,844,118 restricted shares with a fair value of $1,568,000 and issued options with an aggregate fair value of $195,000 ; vesting is service-contingent over ~34 months.

[10-Q] PEDEVCO Corp. Quarterly Earnings Report

Filing Impact

(Neutral)

Filing Sentiment

(Neutral)

Form Type

10-Q

Rhea-AI Filing Summary

PEDEVCO Corp. reported material credit losses and operational financing arrangements in its Q2 2025 Form 10-Q. The company recognized a $1,378,000 note receivable credit loss related to amounts owed by Tilloo following the Milnesand Sale, including a $1,122,436 promissory note bearing 10% annual interest and missed payments due January 8, 2025; a notice of default was issued. The company received $1.7 million from a private operator under an agreement to expand Roth and Amber DSUs and amended acreage and operatorship arrangements. PEDEVCO reimbursed regulatory plugging costs of $297,000 during the six months ended June 30, 2025. Noncash share awards include 1,844,118 restricted shares (fair value $1,568,000) and options with aggregate fair value $195,000. The company recorded an $414,000 income tax benefit for the period and disclosed that its disclosure controls and procedures were not effective due to unresolved material weaknesses from the 2024 year-end audit. PEDEVCO has an undrawn reserve-based lending facility with an initial borrowing base of $20.0 million and maximum revolving capacity of $250 million.

Positive

$1.7 million received from an operator to joint-develop Roth and Amber DSUs, with operatorship transferred to the operator
Access to a reserve-based lending facility with an initial borrowing base of $20.0 million and aggregate capacity of $250 million (undrawn)
Recorded an $414,000 income tax benefit for the six months ended June 30, 2025

Negative

Recognized a $1,378,000 note receivable credit loss related to the Tilloo promissory note and wrote off $111,000 of post-closing adjustments
Tilloo failed to make the initial payment due January 8, 2025; Company issued a notice of default and is pursuing collection remedies
Management concluded disclosure controls and procedures were not effective due to unresolved material weaknesses from the 2024 year-end
Share-based compensation and awards: 1,844,118 restricted shares (fair value $1,568,000) and options with aggregate fair value $195,000, increasing noncash expense and potential dilution
Reimbursed $297,000 in plugging and abandonment costs under the SFO during the six months ended June 30, 2025

Insights

TL;DR: Material credit loss and unresolved control weaknesses weigh on near-term financial clarity; available RBL capacity is a liquidity positive but undrawn.

The $1.378M note receivable credit loss tied to the Tilloo promissory note and subsequent default is a tangible hit to results and reduces recoverable assets. The company offset some operational needs via a $1.7M payment from a private operator and retains access to a $20M borrowing base (aggregate capacity $250M) that remains undrawn. Noncash compensation (restricted stock and options) increases share鈥慴ased expense and dilutive potential. The income tax benefit of $414K improves reported net results but reflects tax accounting changes rather than operating cash generation. Overall, the report signals stressed receivables and governance weaknesses that complicate near鈥憈erm earnings quality.

TL;DR: Credit exposure to a single counterparty and unresolved material weaknesses in controls are the primary risk drivers in this filing.

Tilloo鈥檚 failure to make payments under the five鈥憏ear note and the full write鈥憃ff of certain receivables indicate concentrated counterparty risk and collection uncertainty. The notice of default and ongoing consideration of remedies confirm litigation/collection risk. The Company鈥檚 disclosure controls and procedures were judged not effective, which raises the probability of future reporting errors or delayed disclosures. Lease expirations (notably 5,371 net acres in the D鈥慗 Basin over two years) and reliance on drilling to hold acreage increase operational execution risk. While the RBL provides optionality, covenant requirements (net leverage and current ratio thresholds) could constrain flexibility if operating performance weakens.

08/14/2025 - 04:26 PM

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: June 30, 2025

☐	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: 001-35922

PEDEVCO Corp.

(Exact name of registrant as specified in its charter)

Texas		22-3755993
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

575 N. Dairy Ashford, Suite 210, Houston, Texas		77079
(Address of principal executive offices)		(Zip Code)

(713) 221-1768

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.001 par value per share	PED	NYSE American

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 ☒ 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 ☒ No ☐

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

Large accelerated filer	☐	Accelerated filer	☐
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 ☒

At August 13, 2025, there were 91,979,352 shares of the Registrant’s common stock outstanding.

PEDEVCO CORP.

TABLE OF CONTENTS

		Page
Cautionary Note Regarding Forward-Looking Statements		3

PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements	4

	Consolidated Balance Sheets as of June 30, 2025 (Unaudited) and December 31, 2024	4

	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2025 and 2024 (Unaudited)	5

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2025 and 2024 (Unaudited)	6

	Consolidated Statements of Shareholders’ Equity for the Three and Six Months Ended June 30, 2025 and 2024 (Unaudited)	7

	Notes to Unaudited Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30

Item 4.	Controls and Procedures	30

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	31

Item 1A.	Risk Factors	31

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31

Item 3.	Defaults Upon Senior Securities	31

Item 4.	Mine Safety Disclosures	31

Item 5.	Other Information	31

Item 6.	Exhibits	32

Signatures		33

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Some of the statements contained in this Quarterly Report on Form 10-Q (this “Report”) include forward-looking statements within the meaning of the federal securities laws, including Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended and the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “projects,” “estimates,” “plans,” “may,” and similar expressions or future or conditional verbs such as “should”, “would”, and “could” are generally forward-looking in nature and not historical facts. Forward-looking statements which are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs and cash flows, prospects, plans and objectives of management are forward-looking statements. These forward-looking statements were based on various factors and were derived utilizing numerous important assumptions and other important factors that could cause actual results to differ materially from those in the forward-looking statements. Forward-looking statements include the information concerning our future financial performance, business strategy, projected plans and objectives. These factors include, among others, the factors set forth below under the heading “Risk Factors.” Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Most of these factors are difficult to predict accurately and are generally beyond our control. Readers are cautioned not to place undue reliance on these forward-looking statements.

Forward-looking statements may include statements about:

●	our business strategy;
●	our reserves;
●	our technology;
●	our cash flows and liquidity;
●	our financial strategy, budget, projections and operating results;
●	oil and natural gas realized prices;
●	timing and amount of future production of oil and natural gas;
●	the availability of oil field labor;
●	the amount, nature and timing of capital expenditures, including future exploration and development costs;
●	drilling of wells;
●	government regulation and taxation of the oil and natural gas industry;
●	changes in, and interpretations and enforcement of, environmental and other laws and other political and regulatory developments, including in particular additional permit scrutiny in Colorado;
●	exploitation projects or property acquisitions;
●	costs of exploiting and developing our properties and conducting other operations;
●	general economic conditions in the United States and around the world, including the effect of regional or global health pandemics (such as, for example, the 2019 coronavirus (“COVID-19”)), recent changes in inflation and interest rates, tariffs and trade wars, and risks of recessions, including as a result thereof;
●	competition in the oil and natural gas industry;
●	effectiveness of our risk management activities;
●	environmental liabilities;
●	counterparty credit risk;
●	developments in oil-producing and natural gas-producing countries;
●	political conditions in or affecting oil, natural gas liquids (NGLs) and natural gas producing regions and/or pipelines, including in Eastern Europe, the Middle East and South America, for example, as experienced with the Russian invasion of the Ukraine in February 2022 and the current war in Israel, which conflicts are ongoing;
●	our future operating results;
●	future acquisition transactions;
●	our estimated future reserves and the present value of such reserves; and
●	our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

All forward-looking statements speak only at the date of the filing of this Quarterly Report. The reader should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can provide no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 31, 2025. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. We do not undertake any obligation to update or revise publicly any forward-looking statements except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PEDEVCO CORP.

CONSOLIDATED BALANCE SHEETS

(amounts in thousands, except share and per share data)

Assets	June 30, 2025 (Unaudited)			December 31, 2024
Current assets:
Cash and cash equivalents	$	8,467		$	4,010
Note receivable, current		-			293
Accounts receivable – oil and gas		8,556			7,995
Prepaid expenses and other current assets		568			917
Total current assets		17,591			13,215

Oil and gas properties:
Oil and gas properties, subject to amortization, net		96,194			95,070
Oil and gas properties, not subject to amortization		6,223			8,442
Total oil and gas properties, net		102,417			103,512

Note receivable		-			933
Operating lease – right-of-use asset		299			224
Deferred income taxes		13,165			12,751
Other assets		3,346			3,210
Total assets	$	136,818		$	133,845

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	5,782		$	2,625
Accrued expenses		1,561			2,255
Revenue payable		2,467			1,266
Operating lease liabilities – current		174			99
Asset retirement obligations – current		580			663
Total current liabilities		10,564			6,908

Long-term liabilities:
Operating lease liabilities, net of current portion		125			129
Asset retirement obligations, net of current portion		5,477			5,708
Total liabilities		16,166			12,745

Commitments and contingencies

Shareholders’ equity:
Common stock, $0.001 par value, 200,000,000 shares authorized; 91,829,352 and 89,355,267 shares issued and outstanding, respectively		92			89
Additional paid-in capital		228,098			227,013
Accumulated deficit		(107,538	)		(106,002	)
Total shareholders’ equity		120,652			121,100
Total liabilities and shareholders’ equity	$	136,818		$	133,845

See accompanying notes to unaudited consolidated financial statements.

Table of Contents

PEDEVCO CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(amounts in thousands, except share and per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2025			2024			2025			2024
Revenue:
Oil and gas sales	$	6,972		$	11,811		$	15,708		$	19,927

Operating expenses:
Lease operating costs		2,799			3,548			6,211			6,079
Selling, general and administrative expense		1,693			1,383			3,289			2,878
Impairment of oil and gas properties		510			-			742			-
Depreciation, depletion, amortization and accretion		3,857			4,242			7,203			7,727
Total operating expenses		8,859			9,173			17,445			16,684

Gain on sale of oil and gas properties		1,021			-			1,021			-
Note receivable - credit loss		(1,378)			-			(1,378)			-

Operating income (expense)		(2,244	)		2,638			(2,094	)		3,243

Other income (expense), net:
Interest income		63			93			127			242
Gain on sale of fixed asset		-			-			-			12
Other income (expense)		15			(50	)		17			(43	)
Total other income		78			43			144			211
Income (loss) before income taxes		(2,166	)		2,681			(1,950	)		3,454
Income tax benefit		490			-			414			-

Net (loss) income	$	(1,676	)	$	2,681		$	(1,536	)	$	3,454

Income (loss) per common share:
Basic	$	(0.02	)	$	0.03		$	(0.02	)	$	0.04
Diluted	$	(0.02	)	$	0.03		$	(0.02	)	$	0.04

Weighted average number of common shares outstanding:
Basic		91,403,552			89,326,805			91,137,310			89,040,322
Diluted		91,403,552			89,326,805			91,137,310			89,040,322

See accompanying notes to unaudited consolidated financial statements.

Table of Contents

PEDEVCO CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(amounts in thousands)

	Six Months Ended June 30,
	2025			2024
Cash Flows From Operating Activities:
Net (loss) income	$	(1,536	)	$	3,454
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		7,203			7,727
Impairment of oil and gas properties		742			-
Note receivable-credit loss		1,378			-
Amortization of right-of-use asset		75			55
Share-based compensation expense		949			937
Disposition of escrow cash account		-			(50	)
Deferred income taxes		(414	)		-
Gain on sale of oil and gas properties, net		(1,021	)		-
Gain on disposal of fixed asset		-			(12	)
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		(672	)		(2,837	)
Note receivable accrued interest		(41	)		(53	)
Prepaid expenses and other current assets		349			125
Accounts payable		(2,224	)		(359	)
Accrued expenses		(481	)		(6,613	)
Revenue payable		1,201			(2,079	)
Net cash provided by operating activities		5,508			295

Cash Flows From Investing Activities:
Cash paid for drilling and completion costs		(3,675	)		(12,290	)
Cash received for sale of oil and gas properties		2,635			-
Cash received for sale of vehicle		-			12
Cash paid for vehicle		-			(55	)
Net cash used in investing activities		(1,040	)		(12,333	)

Cash Flows From Financing Activities:
Proceeds from issuance of shares, net of offering costs		139			-
Net cash provided by investing activities		139			-

Net increase (decrease) in cash and restricted cash		4,607			(12,038	)
Cash and restricted cash at beginning of period		6,607			20,715
Cash and restricted cash at end of period	$	11,214		$	8,677

Supplemental Disclosure of Cash Flow Information
Noncash investing and financing activities:
Change in accrued oil and gas development costs	$	(4,780	)	$	5,067
Changes in estimates of asset retirement costs, net	$	119		$	145
Issuance of restricted common stock	$	3		$	2

See accompanying notes to unaudited consolidated financial statements.

Table of Contents

PEDEVCO CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2025 AND 2024

(Unaudited)

(amounts in thousands, except share amounts)

	Common Stock				Additional Paid-in			Accumulated
	Shares		Amount		Capital			Deficit			Total
Balances at December 31, 2024		89,495,267	$	89	$	227,013		$	(106,002	)	$	121,100
Issuance of restricted common stock		1,844,118		2		(2	)		-			-
Share-based compensation		-		-		475			-			475
Net income		-		-		-			140			140
Balances at March 31, 2025		91,339,385	$	91	$	227,486		$	(105,862	)	$	121,715
Issuance of common stock for cash proceeds, net		489,967		1		138			-			139
Share-based compensation		-		-		474			-			474
Net loss		-		-		-			(1,676	)		(1,676	)
Balances at June 30, 2025		91,829,352	$	92	$	228,098		$	(107,538	)	$	120,652

	Common Stock					Additional Paid-in			Accumulated
	Shares			Amount		Capital			Deficit			Total
Balances at December 31, 2023		87,250,267		$	87	$	225,156		$	(126,477	)	$	98,766
Issuance of restricted common stock		2,105,000			2		(2	)		-			-
Share-based compensation		-			-		475			-			475
Net income		-			-		-			773			773
Balances at March 31, 2024		89,355,267			89		225,629			(125,704	)		100,014
Rescinded restricted common stock		(70,000	)		-		-			-			-
Share-based compensation		-			-		462			-			462
Net income		-			-		-			2,681			2,681
Balances at June 30, 2024		89,285,267		$	89	$	226,091		$	(123,023	)	$	103,157

See accompanying notes to unaudited consolidated financial statements.

Table of Contents

PEDEVCO CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

The accompanying interim unaudited consolidated financial statements of PEDEVCO Corp. (“PEDEVCO” or the “Company”), have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and the rules of the Securities and Exchange Commission (“SEC”) and should be read in conjunction with the audited financial statements and notes thereto contained in PEDEVCO’s latest Annual Report filed with the SEC on Form 10-K. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of the financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the interim unaudited consolidated financial statements that would substantially duplicate disclosures contained in the audited financial statements for the most recent fiscal year, as reported in the Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 31, 2025 (the “2024 Annual Report”), have been omitted.

The Company’s consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and subsidiaries in which the Company has a controlling financial interest. All significant inter-company accounts and transactions have been eliminated in consolidation.

The Company’s future financial condition and liquidity will be impacted by, among other factors, the success of our drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the actual cost of exploration, appraisal and development of our prospects, and the prevailing prices and demand for oil and natural gas.

NOTE 2 – DESCRIPTION OF BUSINESS

PEDEVCO is an oil and gas company focused on the development, acquisition and production of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, the Company focuses 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. The Company’s 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. The Company holds its Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through its wholly-owned operating subsidiary, Pacific Energy Development Corp. (“PEDCO”), which asset the Company refers to as its “Permian Basin Asset,” and it holds its D-J Basin acres located in Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, through its wholly-owned subsidiary, PRH Holdings LLC, and which asset the Company refers to as its “D-J Basin Asset.”

The Company believes that horizontal development and exploitation of conventional assets in the Permian Basin and development of the Wattenberg and Wattenberg Extension in the D-J Basin represent among the most economic oil and natural gas plays in the United States (“U.S.”). Moving forward, the Company plans to optimize its existing assets and opportunistically seek additional acreage proximate to its currently held core acreage, as well as other attractive onshore U.S. oil and gas assets that fit the Company’s acquisition criteria, that Company management believes can be developed using its technical and operating expertise and be accretive to shareholder value.

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Company has provided a discussion of significant accounting policies, estimates and judgments in its 2024 Annual Report. There have been no changes to the Company’s significant accounting policies since December 31, 2024.

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Recently Issued Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board (“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.

NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregation of Revenue from Contracts with Customers. The following table disaggregates revenue by significant product type in the periods indicated (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Oil sales	$	6,180	$	10,952	$	13,254	$	18,406
Natural gas sales		323		290		1,165		623
Natural gas liquids sales		469		569		1,289		898
Total oil and gas sales	$	6,972	$	11,811	$	15,708	$	19,927

There were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of June 30, 2025.

NOTE 5 – CASH

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows (in thousands):

	June 30, 2025		December 31, 2024
Cash	$	8,467	$	4,010
Restricted cash included in other assets*		2,747		2,597
Total cash and restricted cash	$	11,214	$	6,607

* Increase in restricted cash is related to additional collateral for a surety bond required by the Colorado Bureau of Land Management with respect to the Company’s Colorado operations.

NOTE 6 – OIL AND GAS PROPERTIES

The following table summarizes the Company’s oil and gas activities by classification for the six months ended June 30, 2025 (in thousands):

	December 31, 2024*			Additions			Disposals			Transfers			June 30, 2025
Oil and gas properties, subject to amortization	$	210,039		$	2,344		$	-		$	5,561		$	217,944
Oil and gas properties, not subject to amortization		14,738			6,111			(2,028	)		(5,561	)		13,260
Asset retirement costs		4,326			119			(91	)		-			4,354
Accumulated depreciation and depletion		(81,015	)		(6,808	)		-			-			(87,823	)
Accumulated impairment		(44,576)			(742)			-			-			(45,318)
Total oil and gas properties, net	$	103,512		$	1,024		$	(2,119	)	$	-		$	102,417

*Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation, which had no effect on the previously reported total assets, total liabilities, total shareholders’ equity, results of operations or cash flows.

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For the six-month period ended June 30, 2025, the Company incurred $8,455,000 of capital costs primarily related to the Company’s completion operations with respect to four operated wells recently drilled and completed with a third-party in the Permian Basin.

Additionally, for the six-month period ended June 30, 2025, the Company recorded an impairment of oil and gas properties of $742,000 related to undeveloped leases representing 1,007 net acres in the D-J Basin that it allowed to expire or had no plans to drill prior to expiration.

In February 2025, the Company entered into a joint development agreement with a private equity-backed D-J Basin E&P Company (“Operator”), pursuant to which the parties agreed to jointly participate in the expansion and development of the Company’s Roth and Amber drilling and spacing units (“DSUs”) located in Weld County, Colorado. The Operator paid to the Company $1.7 million, and the Company agreed to amend the Company’s existing Roth and Amber DSUs to increase each to 1,600 acres and transfer operatorship of the DSUs to the Operator.

In February 2025, the Company recognized $0.3 million in disposition expense related to the sale of certain capitalized equipment to a third-party in the D-J Basin.

In April 2025, the Company sold all of its operated production in Weld County, Colorado to a private buyer for an adjusted price of $606,000. The sale included wellbore and surface equipment only for the Company’s 17 operated wells in its D-J Basin Asset, with the Company retaining ownership in all its existing leasehold. The effective date of the sale is January 1, 2025. As a result, the Company recorded a gain on sale of oil and gas properties of $1,021,000 in its consolidated statements of operations for the three and six months ended June 30, 2025.

During the six months ended June 30, 2025, the Company also acquired approximately 63 net mineral acres and 224 net lease acres in and around its existing footprint in the D-J Basin through multiple transactions at total acquisition and due diligence costs of $79,000 and $134,000, respectively.

Depletion expense recorded for production on proved properties for the three and six months ended June 30, 2025 and 2024, amounted to $2,766,000, compared to $4,042,000, and $6,808,000, compared to $7,207,000, respectively.

NOTE 7 – NOTE RECEIVABLE

On November 9, 2023, in accordance with the sale of our then wholly-owned subsidiary EOR Operating Company (“EOR”) to Tilloo Exploration and Production LLC (“Tilloo”), the Company entered into a five-year secured promissory note (the “Note”) with Tilloo, bearing interest at 10% per annum, with no payments due until January 8, 2025, and fully-amortized payments due monthly over the remaining four years of the term thereafter until maturity. The Note contains customary events of default and is secured by a lien over all the assets and capital shares of EOR created under a Security Agreement, a Security Agreement (Pledge of Corporate Securities), and a Mortgage entered into by and between the Company and Tilloo.

Tilloo failed to make its initial installment payment on January 8, 2025, and has not made any subsequent payments as of June 30, 2025. The Company issued a notice of default under the Note to Tilloo in mid-January 2025, and sought to work with Tilloo into April 2025 in an effort to either restructure the Note or arrange for the sale of the assets securing the same to an unaffiliated third-party buyer, with proceeds of such sale to be applied toward repayment of the Note. However, as the Company’s efforts to work with Tilloo were unsuccessful through April 2025, and due to Tilloo’s sustained default and a determination by the Company that the prospect of recovery is remote, the Company has fully written off the outstanding balance of the Note as of June 30, 2025. Accordingly, a $1,267,000 bad debt expense has been recognized in the consolidated statements of operations for the three and six months ended June 30, 2025. However, the Company continues to consider avenues and remedies available to collect on all amounts due and owing to the Company from Tilloo. Additionally, the Company has fully written off post-closing adjustments receivable due from Tilloo related to the sale of EOR in the amount of $111,000. These write-offs reflect the Company's decision that the carrying value of the Note and post-closing adjustments receivable are no longer recoverable. Taken together, the Company recognized a total of $1,378,000 in bad note receivable - credit loss in the consolidated statements of operations for the three and six months ended June 30, 2025.

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NOTE 8 – ASSET RETIREMENT OBLIGATIONS

Activity related to the Company’s asset retirement obligations is as follows (in thousands):

	Six Months Ended June 30, 2025
Balance at the beginning of the period ⁽¹⁾	$	6,371
Accretion expense		369
Liabilities settled		(297	)
Disposition of liabilities		(505	)
Changes in estimates, net		119
Balance at end of period ⁽²⁾	$	6,057

(1)	Includes $663,000 of current asset retirement obligations at December 31, 2024.

(2)	Includes $580,000 of current asset retirement obligations at June 30, 2025.

In New Mexico, the Company, through its New Mexico operating subsidiary Ridgeway Arizona Oil Corp. (“RAZO”), has entered into a Stipulated Final Order (“SFO”) with Director of the Oil and Gas Conservation Division of New Mexico (the “OCD”) pursuant to which, among other things, RAZO agreed to reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset at a rate of $2.00 per gross barrel of oil sold by RAZO during any production reporting period, subject to a minimum payment of $30,000 per month by RAZO. RAZO has been timely paying each reimbursement invoice received from the OCD in accordance with the SFO and is in full compliance with the SFO. The SFO superseded all previous Agreed Compliance Orders, as amended, entered into by and between RAZO and the OCD. During the six months ended June 30, 2025, the Company reimbursed the OCD $297,000 in plugging and abandoning costs related to the SFO.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

Lease Agreements

Currently, the Company has one operating lease for office space that requires Accounting Standards Codification (“ASC”) Topic 842 treatment, discussed below.

The Company’s leases typically do not provide an implicit rate. Accordingly, the Company is required to use its incremental borrowing rate in determining the present value of lease payments based on the information available at the commencement date. The Company’s incremental borrowing rate would reflect the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. However, the Company currently maintains no debt, and in order to apply an appropriate discount rate, the Company used a borrowing rate obtained from a financial institution at which it maintains banking accounts.

In December 2022, the Company entered into a lease agreement for approximately 5,200 square feet of office space in Houston, Texas, that commenced on September 1, 2023, which expires on February 28, 2027. The remaining monthly payments are approximately $15,800 through February 2026 and increase to approximately $16,000 through the end of the lease. The Company paid a security deposit of $14,700.

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Supplemental cash flow information related to the Company’s operating office lease is included in the table below (in thousands):

	Six Months Ended
	June 30, 2025
Cash paid for amounts included in the measurement of lease liabilities	$	75

Supplemental balance sheet information related to operating leases is included in the table below (in thousands):

	June 30, 2025
Operating lease – right-of-use asset	$	299

Operating lease liabilities - current	$	174
Operating lease liabilities - long-term		125
Total lease liability	$	299

The weighted-average remaining lease term for the Company’s operating lease is 1.7 years as of June 30, 2025, with a weighted-average discount rate of 7.90%.

Lease liability with enforceable contract terms that have greater than one-year terms are as follows (in thousands):

Remainder of 2025	$	95
2026		191
Thereafter		32
Total lease payments		318
Less imputed interest		(19	)
Total lease liability	$	299

Leasehold Drilling Commitments

The Company’s oil and gas leasehold acreage is subject to expiration of leases if the Company does not drill and hold such acreage by production or otherwise exercise options to extend such leases, if available, in exchange for payment of additional cash consideration. In the D-J Basin, 129 net acres expire during the remainder of 2025, and 5,371 net acres expire within the next two-year period (net to our direct ownership interest only). In the Permian Basin, no net acres are due to expire during the remainder of 2025, and no net acres expire within the next two-year period (net to our direct ownership interest only). The Company plans to hold significantly all of this acreage through a program of drilling and completing producing wells. If the Company is not able to drill and complete a well before lease expiration, the Company may seek to extend leases where able.

Other Commitments

Although the Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Company is not currently a party to any material legal proceeding. In addition, the Company is not aware of any material legal or governmental proceedings against it or contemplated to be brought against it.

As part of its regular operations, the Company may become party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its commercial operations, products, employees and other matters.

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Although the Company provides no assurance about the outcome of any future legal and administrative proceedings and the effect such outcomes may have on the Company, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the Company’s financial condition or results of operations.

Milnesand Sale Dispute and Tilloo Note Default

On November 4, 2024, the Company received correspondence from legal counsel to Tilloo Exploration & Production, LLC seeking to recover damages which Tilloo is alleging were caused by alleged intentional misrepresentations made by principals of the Company to principals of Tilloo in connection with Tilloo’s acquisition of the Milnesand and Sawyer fields in New Mexico from the Company for aggregate consideration of $1,122,436 effective August 1, 2023 (the “Milnesand Sale”), which consideration was paid to the Company by Tilloo via a five-year secured promissory note with 10% annual interest and no payments due until January 8, 2025 (the “Tilloo Note”). The Company does not believe any misrepresentations were made by the Company or its principals in the Milnesand Sale and that the claims will fail as a matter of law. The Company has not received any correspondence from Tilloo regarding the allegations made in November 4, 2024 correspondence subsequent to receipt of the same from Tilloo, and Tilloo failed to make the initial installment payment due under the Tilloo Note on January 8, 2025. The Company issued a notice of default under the Tilloo Note to Tilloo in mid-January 2025, and the Company continues to consider avenues and remedies available to collect on all amounts due and owing to the Company from Tilloo.

NOTE 10 – SHAREHOLDERS’ EQUITY

Common Stock

During the six months ended June 30 2025, the Company granted an aggregate of 2,105,000 restricted stock awards to various employees of the Company.

During the month of June 2025, the Company sold an aggregate of 489,967 shares of common stock in five separate sales at sales prices ranging between $0.716 to $0.801 per share via an ongoing “at the market offering” (the “ATM 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.

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.

NOTE 11 – SHARE-BASED COMPENSATION

The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award over the vesting period.

Common Stock

On January 23, 2025, restricted stock awards were granted to officers and employees of the Company for an aggregate of 1,844,118 shares of the Company’s restricted common stock under the Company’s 2021 Plan. The grant for the 1,844,118 shares of restricted common stock vest as follows: 33.3% vesting on the 10-month anniversary of the vesting commencement date, 33.3% vesting on the 22-month anniversary date of the vesting commencement and 33.4% vesting on the 34-month anniversary date of the vesting, contingent upon the recipient’s continued service with the Company. These shares have a total fair value of $1,568,000 based on the market price on the grant date.

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Stock-based compensation expense recorded relating to the vesting of restricted stock for the three and six months ended June 30, 2025 and 2024, was $419,000 and $394,000 and $838,000 and $795,000, respectively. The remaining unamortized stock-based compensation expense at June 30, 2025 related to restricted stock was $1,537,000.

Options

On January 23, 2025, the Company granted options to purchase an aggregate of 464,000 shares of common stock to various Company employees at an exercise price of $0.85 per share under the Company’s 2021 Plan. The options have a term of five years and fully vest in November 2027, with 33.3% vesting on the 10-month anniversary of the vesting commencement date, 33.3% vesting on the 22-month anniversary date of the vesting commencement and 33.4% vesting on the 34-month anniversary date of the vesting, contingent upon the recipient’s continued service with the Company. The aggregate fair value of the options on the date of grant, using the Black-Scholes model, was $195,000. Variables used in the Black-Scholes option-pricing model for the options issued include: (1) a discount rate of 4.45% based on the applicable US Treasury bill rate, (2) expected term of 3.5 years, (3) expected volatility of 64.5% based on the trading history of the Company, and (4) zero expected dividends.

During the three and six months ended June 30, 2025 and 2024, the Company recognized stock option expense of $55,000 and $68,000 and $111,000 and $142,000, respectively. The remaining amount of unamortized stock options expense at June 30, 2025 was $210,000.

The intrinsic value of outstanding and exercisable options at June 30, 2025 was $-0-.

Option activity during the six months ended June 30, 2025, was:

	Number of Stock Options			Weighted Average Exercise Price		Weighted Average Remaining Contract Term (Years)
Outstanding at December 31, 2024		1,835,667		$	1.12		2.4
Granted		464,000		$	0.85
Expired/Canceled		(215,667	)	$	1.68
Outstanding at June 30, 2025		2,084,000		$	1.00		2.8
Exercisable at June 30, 2025		1,156,666		$	1.14		1.8

NOTE 12 – EARNINGS (LOSS) PER COMMON SHARE

Earnings (loss) per common share-basic is calculated by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Net income (loss) per common share-diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing net income by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net income (loss) per common share-diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect.

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The calculation of earnings (loss) per share for the periods indicated below were as follows (amounts in thousands, except share and per share data):

	Three Months Ended June 30,					Six Months Ended June 30,
	2025			2024		2025			2024
Numerator:
Net (loss) income	$	(1,676	)	$	2,681	$	(1,536	)	$	3,454

Denominator:
Weighted average common shares – basic		91,403,552			89,326,805		91,137,310			89,040,322

Dilutive effect of common stock equivalents:
Options		-			-		-			-

Denominator:
Weighted average common shares – diluted		91,403,552			89,326,805		91,137,310			89,040,322

Earnings per share – basic	$	(0.02	)	$	0.03	$	(0.02	)	$	0.04
Earnings per share – diluted	$	(0.02	)	$	0.03	$	(0.02	)	$	0.04

For the three and six months ended June 30, 2025 and 2024, share equivalents related to options to purchase 2,294,000, compared to 1,835,667, and 2,294,000 compared to 1,835,667, shares of common stock, respectively, were excluded from the computation of diluted net income per share as the inclusion of such shares would be anti-dilutive.

NOTE 13 – INCOME TAXES

The Company’s effective tax rate was approximately 21.3% and 0.0% for the six months ended June 30, 2025 and 2024, respectively. The effective tax rate was primarily due to recognized tax benefits in the current period compared to the impact of the full valuation allowance recorded in the prior period. As a result, the Company recognized an income tax benefit of $414,000 for the period ended June 30, 2025.

On July 4, 2025, President Trump signed the One Big Beautiful Bill Act (“OBBBA”) into law. The OBBBA includes, among other things, a permanent extension of 100% bonus depreciation for certain capital expenditures and modifications to the interest expense limitation under Section 163(j). In accordance with ASC Topic 740, Income Taxes, the effects of the tax law are recognized in the period of enactment and therefore not reflected in the Company’s unaudited condensed consolidated financial statements for the three and six months ended June 30, 2025. The Company is evaluating the potential tax impacts of the OBBBA on the consolidated financial statements.

NOTE 14 — SEGMENT INFORMATION

Operating segments are defined as components of an enterprise for which separate financial information is available and regularly evaluated by the Chief Operating Decision Maker (“CODM”) for the purpose of making key operating decisions, allocating resources, and assessing operating performance. The Company operates in one reportable operating segment, oil and natural gas development, exploration and production. The Company’s oil and gas properties are managed as a whole rather than through discrete operating segments. Financial and operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company’s entire portfolio without regard to geographic area, and considers among other things, return on investment, current market conditions, including commodity prices and market supply, availability of services and human resources, and contractual commitments. The Company’s President and Chief Executive Officer is its CODM.

The Company’s profitability measure is consolidated net income which is used to assess budgeted versus actual results and drives the Company’s operating cash flow. The CODM reviews significant consolidated forecasts and results of operations, including return on capital, operating expenses, and cash flow when making decisions such as the allocation of capital. The financial position, results of operations and cash flows of the Company’s reportable operating segment are consistent with the Company’s consolidated financial statements included herein.

NOTE 15 – SUBSEQUENT EVENTS

On July 7, 2025, the Company appointed John K. Howie to the Company's Board of Directors and as a member of the Company's Audit Committee, Compensation Committee, and Nominating and Corporate Governance Committee. As consideration for Mr. Howie joining the Board of Directors, the Board granted Mr. Howie 150,000 shares of restricted common stock of the Company pursuant to the Company’s 2021 Equity Incentive Plan, as amended. which shares vest on July 7, 2026, subject to Mr. Howie continuing to serve as a member of the Company’s Board of Directors on such vesting date, and subject to the terms and conditions of a Restricted Shares Grant Agreement entered into by and between the Company and Mr. Howie.

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ITEM 2. 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 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 for the year ended December 31, 2024, as filed with the Securities and Exchange Commission on March 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 six months ended June 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 six-month periods ended June 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 June 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 June 30, 2025, we held approximately 17,830 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 June 30, 2025, we held interests in 39 gross (35.5 net) wells in our Permian Basin Asset, of which 32 gross (28.5 net) wells were active producers, five gross (five net) wells were inactive, and two gross (two net) wells were active salt water disposal wells (“SWD’s”), all of which were held by PEDCO and operated by RAZO, and interests in 71 gross (6.9 net) wells in our D-J Basin Asset held by PRH, which includes 54 gross (6.9 net) non-operated wells, 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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Strategy

We believe that horizontal development and exploitation of conventional assets in the Permian Basin and development of the Wattenberg and Wattenberg Extension in the D-J Basin, 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 other attractive onshore U.S. oil and gas assets that fit our acquisition criteria, that Company management believes can be developed using our technical and operating expertise and be accretive to stockholder value.

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 Permian Basin and the D-J 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.

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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 Permian Basin acreage so we can dictate the pace of development in order to execute our business plan. Our D-J Basin strategy is to participate in projects we deem highly economic on an operated or non-operated basis as our acreage position does not always allow for us to serve as operator in the D-J Basin. Our net capital expenditures for 2025 are estimated at the time of this filing to range between $27 million to $33 million. This estimate includes a range of $24.5 million to $30.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets (of which we have incurred approximately $7.8 million through June 30, 2025) and approximately $2.5 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 June 30, 2025) . We anticipate that approximately 70% to 75% 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, each discussed below. 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.

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) equity infusions or loans (which may be convertible) made available from Dr. Simon G., Kukes, our former CEO and recently appointed Executive Chairman of the Company's Board of Directors, which funding Dr. Kukes is under no obligation to provide, (iv) 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 (v) 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 $20 million and an aggregate maximum revolving credit amount of $250 million (of which none 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.

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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.

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.

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 six-month periods ended June 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.

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

We reported a net loss for the three-month period ended June 30, 2025, of $1.7 million, or ($0.02) per common share, compared to net income for the three-month period ended June 30, 2024 of $2.7 million or $0.03 per share. The decrease in net income of $4.4 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 $3.5 million (a $4.8 million reduction in revenue and a $0.5 million impairment to oil and gas properties, offset by a $0.8 million reduction in other operating expenses), offset by a $1.0 million gain on sale on oil and gas properties from the sale of our operated wells in the D-J Basin (each discussed in more detail below) and an income tax benefit of $0.5 million (see Note 13 – Income Taxes, in the notes to the consolidated financial statements above under “Part I – Financial Information—Item 1. Financial Statements”).

Net Revenues

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

	Three Months Ended June 30,
	2025		2024		Increase (Decrease)			% Increase (Decrease)
Sale Volumes:
Crude Oil (Bbls)		100,249		139,472		(39,223	)	(28%)
Natural Gas (Mcf)		119,493		145,574		(26,081	)	(18%)
NGL (Bbls)		17,863		19,083		(1,220	)	(6%)
Total (Boe) ⁽¹⁾		138,028		182,817		(44,789	)	(24%)

Crude Oil (Bbls per day)		1,102		1,533		(431	)	(28%)
Natural Gas (Mcf per day)		1,313		1,600		(287	)	(18%)
NGL (Bbls per day)		196		210		(14	)	(7%)
Total (Boe per day) ⁽¹⁾		1,517		2,010		(493	)	(25%)

Average Sale Price:
Crude Oil ($/Bbl)	$	61,65	$	78.52	$	(16.87	)	(21%)
Natural Gas ($/Mcf)		2.70		1.99		0.71		36%
NGL ($/Bbl)		26.24		29.84		(3.60	)	(12%)

Net Operating Revenues (in thousands):
Crude Oil	$	6,180	$	10,952	$	(4,772	)	(44%)
Natural Gas		323		290		33		11%
NGL		469		569		(100	)	(18%)
Total Revenues	$	6,972	$	11,811	$	(4,839	)	(41%)

(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 June 30, 2025, decreased $4.8 million, or 41%, to $7.0 million, compared to $11.8 million for the same period a year ago, due to an unfavorable price variance of $2.3 million, due to the average sales price for crude oil and NGL realized by the Company decreasing compared to the three-month period ended June 30, 2024, coupled with an unfavorable volume variance of $2.5 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

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

	Three Months Ended
	June 30,					Increase			% Increase
	2025		2024			(Decrease)			(Decrease)
Direct Lease Operating Expenses	$	1,256	$	1,731		$	(475	)	(27%)
Workovers		469		335			134		40%
Other*		1,074		1,482			(408	)	(28%)
Total Lease Operating Expenses	$	2,799	$	3,548		$	(749	)	(21%)

Depreciation, Depletion,
Amortization and Accretion	$	3,857	$	4,242		$	(385	)	(9%)
Impairment of Oil and Gas Properties	$	510	$	-		$	510		100%

General and Administrative (Cash)	$	1,218	$	921		$	297		32%
Share-Based Compensation (Non-Cash)		475		462			13		3%
Total General and Administrative Expense	$	1,693	$	1,383		$	310		22%

Gain on Sale of Oil and Gas Properties	$	1,021	$	-		$	1,021		100%
Note Receivable - Credit Loss	$	1,378	$	-		$	1,378		100%
Interest Income	$	63	$	93		$	(30	)	(32%)
Other Income (Expense)	$	15	$	(50	)	$	65		130%

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

Lease Operating Expenses. The decrease of $0.7 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 decrease was primarily the result of lower crude oil, natural gas and NGL volumes resulting from the production volume declines noted above.

Impairment of Oil and Gas Properties. The Company recorded an impairment of oil and gas properties of $0.5 million related to undeveloped leases representing 776 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 $0.3 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 gain on the sale of oi land 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.

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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 Income and Other Income (Expense). Includes interest earned from our interest-bearing cash accounts, 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 then wholly-owned subsidiary EOR Operating Company.

Six Months Ended June 30, 2025 vs. Six Months Ended June 30, 2024

We reported a net loss for the six-month period ended June 30, 2024 of $1.5 million, or ($0.02) per share, compared to net income for the six-month period ended June 30, 2024 of $3.5 million or $0.04 per share. The decrease in net income of $5.0 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 4.0 million (a $4.2 million reduction in revenue, and a $0.7 million impairment to oil and gas properties and a $0.1 million of other operating expenses), offset by a $1.0 million gain on sale on oil and gas properties from the sale of our operated wells in the D-J Basin (each discussed in more detail below) and an income tax benefit of $0.4 million (see Note 13 – Income Taxes, in the notes to the consolidated financial statements above under “Part I – Financial Information—Item 1. Financial Statements”).

Net Revenues

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

	Six Months Ended June 30,				Increase			% Increase
	2025		2024		(Decrease)			(Decrease)
Sale Volumes:
Crude Oil (Bbls)		202,931		240,375		(37,444	)	(16%)
Natural Gas (Mcf)		286,227		277,514		8,713		3%
NGL (Bbls)		41,006		30,640		10,366		34%
Total (Boe) ⁽¹⁾		291,642		317,267		(25,625	)	(8%)

Crude Oil (Bbls per day)		1,121		1,321		(200	)	(15%)
Natural Gas (Mcf per day)		1,581		1,525		56		4%
NGL (Bbls per day)		227		168		59		35%
Total (Boe per day) ⁽¹⁾		1,612		1,743		(131	)	(8%)

Average Sale Price:
Crude Oil ($/Bbl)	$	65.32	$	76.57	$	(11.25	)	(15%)
Natural Gas ($/Mcf)		4.07		2.24		1.83		82%
NGL ($/Bbl)		31.43		29.33		2.10		7%

Net Operating Revenues (in thousands):
Crude Oil	$	13,254	$	18,406	$	(5,152	)	(28%)
Natural Gas		1,165		623		542		87%
NGL		1,289		898		391		43%
Total Revenues	$	15,708	$	19,927	$	(4,219	)	(21%)

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

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Total crude oil, natural gas and NGL revenues for the six-month period ended June 30, 2025, decreased $4.2 million, or 21%, to $15.7 million, compared to $19.9 million for the same period a year ago due to an unfavorable price variance of $2.1 million, due to the average sales price for crude oil realized by the Company decreasing compared to the six-month period ended June 30, 2024, coupled with an unfavorable volume variance of $2.1 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.

Operating Expenses and Other Income (Expense)

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

	Six Months Ended
	June 30,					Increase			% Increase
	2025		2024			(Decrease)			(Decrease)
Direct Lease Operating Expenses	$	3,181	$	3,067		$	114		4%
Workovers		731		735			(4	)	(1%)
Other*		2,299		2,277			22		1%
Total Lease Operating Expenses	$	6,211	$	6,079		$	132		2%

Depreciation, Depletion,
Amortization and Accretion	$	7,203	$	7,727		$	(524	)	(7%)
Impairment of Oil and Gas Properties	$	742	$	-		$	742		100%

General and Administrative (Cash)	$	2,340	$	1,941		$	399		21%
Share-Based Compensation (Non-Cash)		949		937			12		1%
Total General and Administrative Expense	$	3,289	$	2,878		$	411		14%

Gain on Sale of Oil and Gas Properties	$	1,021	$	-		$	1,021		100%
Gain on Sale of Fixed Asset	$	-	$	12		$	(12	)	(100%)
Note Receivable - Credit Loss	$	1,378	$	-		$	1,378		100%
Interest Income	$	127	$	242		$	(115	)	(48%)
Other Income (Expense)	$	17	$	(43	)	$	60		(140%)

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

Lease Operating Expenses. The increase of $0.1 million was primarily due to higher direct and variable lease operating expenses associated with the higher oil volume in Q1 2025, which was offset by lower direct and variable lease operating expenses associated with the lower crude oil volumes resulting from the production volume declines in Q2 2025 noted above.

Depreciation, Depletion, Amortization and Accretion. The $0.5 million decrease was primarily the result of lower crude oil volumes resulting from the production volume declines, primarily from Q2 2025, as noted above.

Impairment of Oil and Gas Properties. The Company recorded an impairment of oil and gas properties of $0.7 million related to undeveloped leases representing 1,007 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.

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General and Administrative Expenses (excluding share-based compensation). The $0.4 million increase was primarily the result of additional payroll, audit fees and software licensing fees.

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.

Gain on Sale of Fixed Asset. Relates to the sale of a vehicle and the subsequent purchase of another vehicle in 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 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 three-month period ended June 30, 2025 were from $15.7 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 June 30, 2025, the Company’s total current assets of $17.6 million exceeded its total current liabilities of $10.6 million, resulting in a working capital surplus of $7.0 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 $0.7 million increase in our working capital surplus is primarily related to a proportional increase in production and sales, offset by a proportional increase in payables related to our current capital drilling program, when comparing the current period to the prior period (described above).

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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 June 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.

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 $20 million and an aggregate maximum revolving credit amount of $250 million (of which none has been drawn down by the Company to date), as discussed below, (iv) equity infusions or loans (which may be convertible) made available from Dr. Simon G. Kukes, our former CEO and recently appointed Executive Chairman of the Company's Board of Directors, which funding Dr. Kukes is under no obligation to provide, (v) public or private debt or equity financings, pursuant to the ATM Offering noted above, and (vi) 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 September 11, 2024, the Company entered into a new $250 million reserve-based lending facility (the “Facility”) with Citibank, N.A., as administrative agent, and the lenders (including Citibank, N.A.) from time to time a party thereto. The Facility has a maturity of four years and provides for an initial borrowing base of $20.0 million and an aggregate maximum revolving credit amount of $250 million. The Company has not drawn down any borrowings under the Facility as of the date of this report. The RBL includes customary representations and warranties, and affirmative and negative covenants of the Company for a facility of that size and type, including prohibiting the Loan Parties from creating any indebtedness without the consent of the lenders, subject to certain exceptions, and requiring the Company to have a net leverage ratio (the ratio of (a) total net debt to (b) EBITDAX) of no less than 1.0 to 1.0 and a current ratio (the ratio of (i) consolidated current assets to (ii) consolidated current liabilities) of no less than 1.0 to 1.0. EBITDAX is defined as Earnings Before Interest, Taxes, Depreciation (or Depletion), Amortization, and Exploration Expense. Amounts, if any, that we borrow under the RBL, are due on September 11, 2028.

Cash Flows (in thousands)

	Six Months Ended June 30,
	2025			2024
Cash flows provided by operating activities	$	5,508		$	295
Cash flows used in investing activities		(1,040	)		(12,333	)
Cash flows provided by financing activities		139			-
Net increase (decrease) in cash and restricted cash	$	4,607		$	(12,038	)

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Cash flows provided by operating activities. Net cash used in operating activities increased by $5.2 million for the current year’s period, when compared to the prior year’s period, primarily due to a decrease in net income of $5.0 million, coupled with a $0.5 million decrease in depreciation, depletion and amortization and a $1.0 million gain on a sale of oil and gas properties, offset by a $0.7 million impairment of oil and gas properties, $0.4 increase in deferred tax asset and $1.4 million from a note receivable - credit loss, and a $9.9 million net decrease to our other components of working capital (predominantly from increased expenses from our drilling and completion activities).

Cash flows used in investing activities. Even though total capital costs (accrued and cash) increased to $8.5 million this period from $7.2 million last period (see extract table below from our Consolidated Statements of Cash Flows), net cash used in investing activities actually decreased by $11.3 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.

	Six Months Ended June 30,
	2025			2024
Cash paid for drilling and completion costs		(3,675	)		(12,290	)
Change in accrued oil and gas development costs		(4,780	)		5,067
Total capital costs		(8,455	)		(7,223	)

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.

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):

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	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2025			2024		2025			2024
Net (loss) income	$	(1,676	)	$	2,681	$	(1,536	)	$	3,454
Add (deduct)
Income tax benefit		(490	)		-		(414	)		-
Depreciation, depletion, amortization and accretion		3,857			4,242		7,203			7,727
EBITDA		1,691			6,923		5,253			11,181
Add (deduct)
Share-based compensation		474			462		949			937
Impairment of oil and gas properties		510			-		742			-
Gain on sale of oil and gas properties		(1,021	)		-		(1,021	)		-
Gain on sale of fixed asset		-			-		-			(12	)
Note receivable - credit loss		1,378			-		1,378			-
Adjusted EBITDA	$	3,032		$	7,385	$	7,301		$	12,106

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.

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.

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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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Pursuant to Item 305(e) of Regulation S-K (§ 229.305(e)), the Company is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined by Rule 229.10(f)(1).

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time period specified in the SEC’s rules and forms and is accumulated and communicated to the Company’s management, as appropriate, in order to allow timely decisions in connection with required disclosure.

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”)(the Principal Executive Officer) and Chief Accounting Officer (“CAO”)(the Principal Financial/Accounting Officer), we conducted an evaluation of 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. Based on this evaluation, our CEO and CAO concluded as of June 30, 2025, that our disclosure controls and procedures were not designed at a reasonable assurance level and were not effective to provide reasonable assurance that the information we are required to disclose in reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and (ii) accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Management's conclusion was the result of the material weaknesses identified during the preparation of the Company's year-end consolidated financial statements and reported in Item 9A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, that have not yet been remediated as of June 30, 2025.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended June 30, 2025, that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting, including any corrective actions regarding significant deficiencies and material weaknesses.

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Litigation and Regulatory Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings against us or contemplated to be brought against us.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs and procedures to attempt to reduce and mitigate such environmental risks.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the Commission on March 31, 2024 (the “Form 10-K”), under the heading “Item 1A. Risk Factors”, and investors are encouraged to review such risk factors in the Annual Report, prior to making an investment in the Company. Any of these factors, in whole or in part, could materially and adversely affect the Company’s business, financial condition, operating results and stock price.

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

The Company did not issue or sell any unregistered equity securities during the quarter ended June 30, 2025, and through the date of the filing of this Report.

Use of Proceeds From Sale of Registered Securities

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

ITEM 5. OTHER INFORMATION

(c) Rule 10b5-1 Trading Plans.

Our directors and executive officers may from time to time enter into plans or other arrangements for the purchase or sale of our shares that are intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or may represent a non-Rule 10b5-1 trading arrangement under the Exchange Act. During the quarter ended June 30, 2025, none of the Company’s directors or officers (as defined in Rule 16a-1(f)) adopted or terminated any contract, instruction or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any “non-Rule 10b5-1 trading arrangement”, except as follows:

On, May 20, 2025, each of Paul A. Pinkston, our Chief Accounting Officer, J. Douglas Schick, our President and Chief Executive Officer, Jody Crook, our Chief Commercial Officer, and Clark R. Moore, our Executive Vice President and General Counsel, entered into trading plans which are intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) under the Exchange Act. The trading plans provide for the sale of an aggregate of 108,000, 320,000, 316,667, and 84,962 shares of our common stock, respectively, in connection with the vesting of certain of their equity awards through May 19, 2027. The trading plans each terminate on May 19, 2027, subject to early termination for certain specified events set forth in the respective trading plans. These trading plans were entered into during an open insider trading window.

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ITEM 6. EXHIBITS

		Incorporated By Reference
Exhibit No.	Description	Form	Exhibit	Filing Date	File Number
10.1	PEDEVCO Corp. 2021 Equity Incentive Plan(#)	8-K	10.1	9/1/2021	001-35922
10.2	First Amendment to PEDEVCO Corp. 2021 Equity Incentive Plan(#)	8-K	10.1	8/30/2024	001-35922
10.3	PEDEVCO Corp. 2021 Equity Incentive Plan Form of Restricted Shares Grant Agreement(#)	S-8	99.3	9/1/2021	333-259248
10.4	PEDEVCO Corp. - Form of Indemnification Agreement(#)	8-K	10.11	3/31/2024	001-35922
16.1	Letter from Marcum LLP dated July 8, 2025	8-K	16.1	7/8/2025	001-35922
31.1*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification of 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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	Inline XBRL for the cover page of this Quarterly Report on Form 10-Q, included in the Exhibit 101 Inline XBRL Document Set

* Filed herewith.

** Furnished herewith.

# Indicates management contract or compensatory plan or arrangement.

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SIGNATURES

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

	PEDEVCO Corp.

August 14, 2025	By:	/s/ J. Douglas Schick
		J. Douglas Schick
		President and Chief Executive Officer
		(Principal Executive Officer)

	PEDEVCO Corp.

August 14, 2025	By:	/s/ Paul A. Pinkston
		Paul A. Pinkston
		Chief Accounting Officer
		(Principal Financial and Accounting Officer)

Source:

FAQ

What was the size and status of the Tilloo promissory note disclosed in PED's 10-Q?

The Milnesand Sale consideration was paid via a five-year secured promissory note of $1,122,436 with 10% annual interest and no payments due until January 8, 2025; Tilloo missed the initial payment and the Company issued a notice of default.

How large was the note receivable credit loss recognized by PEDEVCO in Q2 2025?

PEDEVCO recognized a total $1,378,000 in note receivable credit loss for the three and six months ended June 30, 2025, which includes write-offs of post-closing adjustments.

Does PEDEVCO have borrowing capacity available under a credit facility?

Yes. The reserve-based lending facility has an initial borrowing base of $20.0 million and an aggregate maximum revolving credit amount of $250 million; the Company had not drawn on this facility as of the report date.

Were there any governance or control issues disclosed in the filing?

Yes. Management concluded that disclosure controls and procedures were not effective due to material weaknesses identified during the year-end 2024 consolidated financial statement preparation that were not yet remediated as of June 30, 2025.

What noncash compensation did the company record in the period?

The company granted 1,844,118 restricted shares with a fair value of $1,568,000 and issued options with an aggregate fair value of $195,000; vesting is service-contingent over ~34 months.

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[10-Q] PEDEVCO Corp. Quarterly Earnings Report

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FAQ

What was the size and status of the Tilloo promissory note disclosed in PED's 10-Q?

How large was the note receivable credit loss recognized by PEDEVCO in Q2 2025?

Does PEDEVCO have borrowing capacity available under a credit facility?

Were there any governance or control issues disclosed in the filing?

What noncash compensation did the company record in the period?

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[10-Q] PEDEVCO Corp. Quarterly Earnings Report

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Financial Analyst negative

Risk Analyst neutral

FAQ

What was the size and status of the Tilloo promissory note disclosed in PED's 10-Q?

How large was the note receivable credit loss recognized by PEDEVCO in Q2 2025?

Does PEDEVCO have borrowing capacity available under a credit facility?

Were there any governance or control issues disclosed in the filing?

What noncash compensation did the company record in the period?

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