[10-Q] BP Prudhoe Bay Royalty Trust Quarterly Earnings Report

Rhea-AI Filing Summary

BP Prudhoe Bay Royalty Trust (BPT) reports that its cash-related balances declined during the period, with a reported balance of $3,117 at June 30, 2025 compared with $4,159 at December 31, 2024. The Trust covered Administrative Expenses from the cash reserve, which reduced the Trust Corpus for the three and six months ended June 30, 2025 versus the comparable 2024 periods. Average WTI prices shown for recent quarter-ends ranged from about $70–$78 per barrel, while Chargeable Costs rose (scheduled increase to $40.25 in 2025), increasing Adjusted Chargeable Costs and contributing to a negative Average Per Barrel Royalty in the reported periods. Average net production declined by about 3.4% year-over-year for the six-month comparison, reflecting natural field decline. The Units were delisted from the NYSE effective July 27, 2025 and may trade on OTC Pink, which could reduce liquidity.

Positive

• None.

Negative

• Trust Corpus decreased from $4,159 at December 31, 2024 to $3,117 at June 30, 2025 due to Administrative Expenses paid from the cash reserve
• Average per-barrel royalty was negative in the reported periods, driven by higher Adjusted Chargeable Costs and lower WTI prices
• Average net production declined ~3.4% for the six-month comparison due to natural decline in the Prudhoe Bay field
• Units were delisted from the NYSE effective July 27, 2025, with potential move to OTC Pink, reducing liquidity and possibly depressing market price
• Trust has precedent of zero royalty payments during low oil-price periods (no royalty receipts for four quarters of 2020 and Q1 2021) and previously insufficient cash reserve to cover Administrative Expenses

Insights

Financial Analyst

TL;DR: Trust cash reserves fell as administrative fees were paid from the reserve; royalties remained negative and trading liquidity was reduced by NYSE delisting.

The filing shows the Trust relying on its cash reserve to pay Administrative Expenses, causing the Trust Corpus to decrease between December 31, 2024 and June 30, 2025. Adjusted Chargeable Costs rose due to an increase in the calendar-year chargeable cost and CPI-driven cost adjustment, while average WTI declined modestly versus prior comparable periods, which together produced a negative average per-barrel royalty. Production volumes declined roughly 3.4% year-over-year for the six-month comparison, consistent with natural field decline. The NYSE delisting effective July 27, 2025 shifts liquidity to OTC Pink, a less liquid market, which can materially affect tradability and pricing for unit holders.

Corporate Governance / Trustee Specialist

TL;DR: Trustee actions and fee payments have depleted the cash reserve, increasing the risk of diminished distributions and complicating orderly wind-up costs if required.

The Trustee paid increased Administrative Expenses from the cash reserve, reducing available funds for distributions. Historical notes indicate periods (2020–2021) when no royalty payments were received and the cash reserve was insufficient to cover administrative fees, illustrating exposure to oil price and cost volatility. The filing references potential termination procedures and related expenses that would be borne by the Trust if revenues remain low, which could further erode unit value.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

or

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

For the quarterly period ended June 30, 2025

or

For the transition period from       to      

Commission File Number 1-10243

BP PRUDHOE BAY ROYALTY TRUST

(Exact Name of Registrant as Specified in its Charter)

Delaware		13-6943724
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
The Bank of New York Mellon Trust Company, N.A. 601 Travis Street, Floor 16 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 483-6020

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

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 ☒

As of August 14, 2025, 21,400,000 Units of Beneficial Interest were outstanding.

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TABLE OF CONTENTS

				Page
		PART I—FINANCIAL INFORMATION
Item 1.		Financial Statements			1
Item 2.		Trustee’s Discussion and Analysis of Financial Condition and Results of Operations			8
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			14
Item 4.		Controls and Procedures			14
		PART II—OTHER INFORMATION
Item 1.		Legal Proceedings			15
Item 1A.		Risk Factors			15
Item 2.		Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities			15
Item 3.		Defaults Upon Senior Securities			15
Item 4.		Mine Safety Disclosures			15
Item 5.		Other Information			15
Item 6.		Exhibits			15

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

BP Prudhoe Bay Royalty Trust

Statement of Assets, Liabilities and Trust Corpus

(Prepared on a modified cash basis)

(Unaudited)

(In thousands, except unit data)

		June 30, 2025				December 31, 2024
Assets
Cash and cash equivalents (Note 3)		$	3,117			$	4,159
Total Assets		$	3,117			$	4,159
Liabilities and Trust Corpus
Accrued expenses		$	325			$	532
Total Liabilities			325				532
Trust Corpus (40,000,000 units of beneficial interest authorized, 21,400,000 units issued and outstanding)			2,792				3,627
Total Liabilities and Trust Corpus		$	3,117			$	4,159

See accompanying notes to financial statements (unaudited).

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BP Prudhoe Bay Royalty Trust

Statements of Cash Earnings and Distributions

(Prepared on a modified cash basis)

(Unaudited)

(In thousands, except unit data)

		Three Months Ended June 30,								Six Months Ended June 30,
		2025				2024				2025				2024
Royalty revenues		$	—			$	—			$	—			$	—
Interest income			36				62				78				129
Less: Trust administrative expenses			(588	)			(556	)			(1,120	)			(894	)
Cash earnings (loss)		$	(552	)		$	(494	)		$	(1,042	)		$	(765	)
Cash distributions		$	—			$	—			$	—			$	—
Cash distributions per unit		$	—			$	—			$	—			$	—
Units outstanding			21,400,000				21,400,000				21,400,000				21,400,000

See accompanying notes to financial statements (unaudited).

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BP Prudhoe Bay Royalty Trust

Statements of Changes in Trust Corpus

(Prepared on a modified cash basis)

(Unaudited)

(In thousands)

		Three Months Ended June 30,								Six Months Ended June 30,
		2025				2024				2025				2024
Trust Corpus at beginning of period		$	3,081			$	4,475			$	3,627			$	4,964
Cash earnings (loss)			(552	)			(494	)			(1,042	)			(765	)
Decrease in accrued expenses			263				221				207				3
Cash distributions			—				—				—				—
Trust Corpus at end of period		$	2,792			$	4,202			$	2,792			$	4,202

See accompanying notes to financial statements (unaudited).

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(1) Formation of the Trust, Organization and Termination

BP Prudhoe Bay Royalty Trust (the “Trust”), a grantor trust, was created as a Delaware business trust pursuant to a Trust Agreement dated February 28, 1989 (the “Trust Agreement”) among The Standard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”)(now known as Hilcorp North Slope, LLC (“HNS”)), The Bank of New York Mellon, as trustee, and BNY Mellon Trust of Delaware (successor to The Bank of New York (Delaware)), as co-trustee. On December 15, 2010, The Bank of New York Mellon resigned as trustee and was replaced by The Bank of New York Mellon Trust Company, N.A., a national banking association, as successor trustee (the “Trustee”).

On February 28, 1989, Standard Oil conveyed an overriding royalty interest (the “Royalty Interest”) to the Trust. The Trust was formed for the sole purpose of owning and administering the Royalty Interest. The Royalty Interest represents the right to receive, a per barrel royalty (the “Per Barrel Royalty”) of 16.4246% on the lesser of (a) the first 90,000 barrels of the average actual daily net production of oil and condensate per quarter or (b) the average actual daily net production of oil and condensate per quarter from HNS’s working interests as of February 28, 1989 in the Prudhoe Bay field situated on the North Slope of Alaska (the “1989 Working Interests”). Trust Unit holders are subject to the risk that production will be interrupted or discontinued or fall, on average, below 90,000 barrels per day in any quarter. BP has guaranteed the performance of BP Alaska of its payment obligations with respect to the Royalty Interest and that guarantee remains in place with respect to the performance of HNS of such payment obligations.

Effective January 1, 2000, BP Alaska and all other Prudhoe Bay working interest owners cross-assigned interests in the Prudhoe Bay field pursuant to the Prudhoe Bay Unit Alignment Agreement. BP Alaska retained all rights, obligations, and liabilities associated with the Trust.

The trustees of the Trust are The Bank of New York Mellon Trust Company, N.A and BNY Mellon Trust of Delaware, a Delaware banking corporation. BNY Mellon Trust of Delaware serves as co-trustee in order to satisfy certain requirements of the Delaware Statutory Trust Act. The Bank of New York Mellon Trust Company, N.A. alone is able to exercise the rights and powers granted to the Trustee in the Trust Agreement.

The Per Barrel Royalty in effect for any day is equal to the price of West Texas Intermediate crude oil (the “WTI Price”) for that day less scheduled Chargeable Costs (adjusted for inflation) and Production Taxes (based on statutory rates then in existence).

The “break-even” price is calculated after the close of a quarter in accordance with the terms of the Overriding Royalty Conveyance. The “break-even” WTI Price changes over time primarily as a result of changes in the Cost Adjustment Factor, which is based on the Consumer Price Index published for the most recently past February, May, August or November, and Production Taxes, as Chargeable Costs remain constant for the calendar year. Additionally, as WTI Prices change, so do the Production Taxes and prescribed deductions, potentially increasing or decreasing the “break-even” WTI Price. The actual “break-even” price is calculated and provided by HNS.

The Trust is passive, with the Trustee having only such powers as are necessary for the collection and distribution of revenues, the payment of Trust liabilities, and the protection of the Royalty Interest. The Trustee, subject to certain conditions, is obligated to establish cash reserves and borrow funds to pay liabilities of the Trust when they become due. The Trustee may sell Trust properties only (a) as authorized by a vote of the Trust Unit holders, (b) when necessary to provide for the payment of specific liabilities of the Trust then due (subject to certain conditions) or (c) upon termination of the Trust. Each Trust Unit issued and outstanding represents an equal undivided share of beneficial interest in the Trust. Royalty payments are received by the Trust and distributed to Trust Unit holders, net of Trust expenses, in the month succeeding the end of each calendar quarter. The Trust will terminate (i) upon a vote of Trust unit holders of not less than 60% of the outstanding Trust Units, or (ii) at such time the net revenues from the Royalty Interest for two successive years are less than $1,000,000 per year (unless the net revenues during such period are materially and adversely affected by certain events).

The Trust did not receive any revenues attributable to any of the four quarters of each of the years ended December 31, 2023, and 2024. Therefore, in accordance with the Trust Agreement, the Trust terminated at 11:59 PM on December 31, 2024, and Trustee has commenced the process of winding up the affairs of the Trust.

(2) Liquidity

In July 1999, the Trustee established a cash reserve to provide liquidity to the Trust during future periods in which the Trust does not receive revenues from the Royalty Interest. The Trustee has drawn funds from the cash reserve account during the quarters in which the quarterly revenues received by the Trust did not exceed the liabilities and expenses of the Trust, and has replenished or otherwise added to the reserve from deductions from quarterly distributions made to Unit holders during periods when the Trust received revenues from the Royalty Interest and Unit holders received distributions.

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Due in part to the economic impacts of the COVID-19 pandemic, the markets experienced a further decline in oil prices in response to oil demand concerns and global storage considerations. As a result of, among other things, lower oil prices and the increase in Chargeable Costs, the Trust received no royalty payments attributable to the four quarters of 2020 or the first quarter of 2021. Therefore, the Trust was unable to make quarterly deductions to make any additions to the funds on deposit in the cash reserve since the January 2020 distribution made for royalty payments attributable to the fourth quarter of 2019. In December 2020, the remaining funds on deposit in the cash reserve were insufficient to pay the Trustee’s fees and administrative fees, expenses, charges and costs, including accounting, engineering, legal, financial advisory, and other professional fees incurred in connection with the Trust (“Administrative Expenses”) in 2020.

Pursuant to the indemnity provisions contained in Section 7.02 of the Trust Agreement, the Trustee made a demand for indemnity and reimbursement of expenses upon HNS in the amount of $537,835, representing the Trust’s unpaid expenses through December 18, 2020. HNS paid the requested funds to the Trustee on December 28, 2020, and the Trustee applied those funds to the Trust’s unpaid expenses in accordance with the Trust Agreement.

During 2021, the Trustee evaluated the adequacy of the cash reserve, the likelihood of the continued and regular receipts of revenues from the Royalty Interest in 2021 and beyond and the anticipated timing of termination of the Trust and determined at that time to further increase the cash reserve to approximately $6,000,000. Considering that the Trust is in wind-down, the Trustee does not expect to maintain the cash reserve at this level, and expects to reevaluate the level of the cash reserve in the event of any future payment from the Royalty Interest and potential proceeds from the sale of the Trust assets. Even if the Trustee determines to reduce the cash reserve target level, if the Trust receives net revenues from the Royalty Interest in any quarter during 2025, it is possible that Unit holders will not receive a distribution on outstanding Units during such periods, because the Trust may withhold funds from any such revenue to first pay accrued Administrative Expenses and retain funds in the cash reserve, before distributing any funds to Unit holders.

Although the Trust received net revenues attributable to the quarters ended June 30, September 30, and December 31, 2021, and each of the four quarters of 2022, the Trust did not receive net revenues attributable to any quarter in 2023, 2024 or the first and second quarters of 2025. There can be no assurance that WTI Prices will return to levels sufficient to result in royalty payments to the Trust in any future quarter.

The Trustee believes the cash reserve is sufficient to pay Trust fees and expenses for the next 12 months.

Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Unit holders, together with interest earned on the funds. Any amounts set aside for the cash reserve are invested by the Trustee in U.S. government or agency securities secured by the full faith and credit of the United States, or mutual funds investing in such securities.

See Note 1 for a discussion of the Trust termination.

(3) Basis of Accounting

The financial statements of the Trust are prepared on a modified cash basis and reflect the Trust’s assets, liabilities, corpus, earnings, and distributions, as follows:

a. Revenues are recorded when received (generally within 15 days of the end of the preceding quarter) and distributions to Trust Unit holders are recorded when paid.

b. Trust expenses (which include accounting, engineering, legal, and other professional fees, trustees’ fees, and out-of-pocket expenses) are recorded on an accrual basis.

c. Cash reserves may be established by the Trustee for certain contingencies that would not be recorded under generally accepted accounting principles.

While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful because quarterly distributions to the Trust Unit holders are based on net cash receipts. The accompanying modified cash basis financial statements contain all adjustments necessary to present fairly the assets, liabilities and corpus of the Trust as of June 30, 2025 and December 31, 2024, and the modified basis of cash earnings and distributions and changes in Trust corpus for the three-month and six-month periods ended June 30, 2025 and 2024. The adjustments are of a normal recurring nature and are, in the opinion of the Trustee, necessary to fairly present the results of operations.

As of June 30, 2025, and December 31, 2024, cash equivalents which represent the cash reserve consist of a Morgan Stanley ILF Treasury Fund and U.S. Treasury Bills with original maturities of ninety days or less.

Estimates and assumptions are required to be made regarding assets, liabilities and changes in Trust corpus resulting from operations when financial statements are prepared. Changes in the economic environment, financial markets and any other parameters used in determining these estimates could cause actual results to differ, and the difference could be material.

These unaudited financial statements should be read in conjunction with the financial statements and related notes in the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024. The cash earnings and distributions for the interim periods presented are not necessarily indicative of the results to be expected for the full year.

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(4) Royalty Interest

At inception in February 1989, the Royalty Interest held by the Trust had a carrying value of $535,000,000. In accordance with generally accepted accounting principles, the Trust amortized the value of the Royalty Interest based on the units of production method. Such amortization was charged directly to the Trust corpus, and did not affect cash earnings. In addition, the Trust periodically evaluated impairment of the Royalty Interest by comparing the undiscounted cash flows expected to be realized from the Royalty Interest to the carrying value, pursuant to the Financial Accounting Standards Board Accounting Standards Codification (ASC) 360, Property, Plant, and Equipment. If the expected future undiscounted cash flows were less than the carrying value, the Trust recognized impairment losses for the difference between the carrying value and the estimated fair value of the Royalty Interest. By December 31, 2010, the Trust had recognized accumulated amortization of $359,473,000 and aggregate impairment write-downs of $175,527,000 reducing the carrying value of the Royalty Interest to zero.

(5) Income Taxes

The Trust files its federal tax return as a grantor trust subject to the provisions of subpart E of Part I of Subchapter J of the Internal Revenue Code of 1986, as amended, rather than as an association taxable as a corporation. The Trust Unit holders are treated as the owners of Trust income and corpus, and the entire taxable income of the Trust will be reported by the Trust Unit holders on their respective tax returns.

If the Trust were determined to be an association taxable as a corporation, it would be treated as an entity taxable as a corporation on the taxable income from the Royalty Interest, the Trust Unit holders would be treated as shareholders, and distributions to Trust Unit holders would not be deductible in computing the Trust’s tax liability as an association.

(6) Alaska Oil and Gas Production Tax

On April 14, 2013, Alaska’s legislature passed an oil-tax reform bill amending Alaska’s oil and gas production tax statutes, AS 43.55.10 et seq (the “Production Tax Statutes”) with the aim of encouraging oil production and investment in Alaska’s oil industry. On May 21, 2013, the Governor of Alaska signed the bill into law as chapter 10 of the 2013 Session Laws of Alaska (the “Act”). Among significant changes, the Act eliminated the monthly “progressivity” tax rate implemented by certain amendments to the Production Tax Statutes in 2006 and 2007, increased the base rate from 25% to 35% and added a stair-step per-barrel tax credit for oil production. This tax credit is based on the gross value at the point of production per barrel of taxable oil and may not reduce a producer’s tax liability below the “minimum tax” (which is a percentage, ranging from zero to 4%, of the gross value at the point of production of a producer’s taxable production during the calendar year based on the average price per barrel for Alaska North Slope crude oil for sale on the United States West Coast for the year) under the Production Tax Statutes. These changes became effective on January 1, 2014.

On January 15, 2014, the Trustee executed a letter agreement with BP Alaska dated January 15, 2014 (the “2014 Letter Agreement”) regarding the implementation of the Act with respect to the Trust. Pursuant to the 2014 Letter Agreement, Production Taxes for the Trust’s Royalty Production will equal the tax for the relevant quarter, minus the allowable monthly stair-step per-barrel tax credits for the Royalty Production during that quarter. If there is a “minimum tax”-related limitation on the amount of the stair-step per-barrel tax credits that could otherwise be claimed for any quarter during the year, any difference between that limitation as preliminarily determined on a quarterly basis and the actual limitation for the entire year will be reflected in the payment to the Trust for the first quarter Royalty Production in the following year.

On July 6, 2015, BP Alaska and the Trustee signed a letter agreement (the “2014 Letter Agreement Amendment”) amending the 2014 Letter Agreement to provide that if there is a “minimum tax”-related limitation on the amount of the stair-step per-barrel tax credits that could otherwise be claimed for any quarter during the year, any difference between that limitation as preliminarily determined on a quarterly basis and the actual limitation for the entire year will be reflected in the payment to the Trust for the fourth quarter Royalty Production payment for such year rather than in the payment to the Trust for the first quarter Royalty Production in the following year.

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(7) Subsequent Events

There was no royalty payment received by the Trust in July 2025 for the quarter ended June 30, 2025.

The Trust announced on June 30, 2025, that it had received notification from the New York Stock Exchange (“NYSE”) of its determination to suspend trading of the Units, effective as of the close of trading on June 30, 2025, and to initiate proceedings to delist the Units. The determination to commence the delisting proceeding resulted from the Trust’s inability to satisfy the continued listing compliance standards set forth under Rule 802.01C of the NYSE Listed Company Manual because the average closing price of the Units fell below $1.00 over a 30 consecutive trading-day period that ended on December 30, 2024, and the Trust was unable to regain compliance with the applicable standards within a cure period that concluded on June 30, 2025.

As a result of the suspension, the Units began trading on July 1, 2025, under the symbol “BPPTU” on the Pink Limited Market (“OTC Pink”), which is operated by OTC Markets Group, Inc. To be quoted on OTC Pink, a market maker must sponsor the security and comply with SEC Rule 15c2-11 before it can initiate a quote in a specific security. OTC Pink is a significantly more limited market than the NYSE, and the quotation of the Units on OTC Pink may result in a less liquid market available for existing and potential unitholders and could further depress the trading price of the Units. On July 17, 2025, the NYSE filed a Form 25 to delist the Units, which became effective on July 27, 2025. There is no assurance that an active market in the Units will develop on OTC Pink.

After the Trust’s termination, RedOaks Energy Advisors, LLC (“RedOaks”) was engaged to provide a valuation opinion and assist with marketing and selling the Trust’s assets, which HNS declined to purchase as of June 2, 2025. Consequently, RedOaks initiated a sale process with bids due on July 29, 2025, and updated bids were due on August 5, 2025. The Trust and RedOaks are reviewing the bid proposals RedOaks received and intend to proceed to negotiating the terms of a potential sale agreement with the highest bidder. The timing and certainty of closing remain unknown.

Subsequent events have been evaluated through the date of this report.

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

Introduction

BP Prudhoe Bay Royalty Trust (the “Trust”), a grantor trust, was created as a Delaware business trust pursuant to a Trust Agreement dated February 28, 1989 (the “Trust Agreement”), among The Standard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”) (now known as Hilcorp North Slope, LLC (“HNS”)), The Bank of New York Mellon, as trustee, and BNY Mellon Trust of Delaware (successor to The Bank of New York (Delaware)), as co-trustee. On December 15, 2010, The Bank of New York Mellon resigned as trustee and was replaced by The Bank of New York Mellon Trust Company, N.A., a national banking association, as successor trustee (the “Trustee”). At the time of formation of the Trust, Standard Oil and BP Alaska were indirect, wholly owned subsidiaries of BP p.l.c. (“BP”).

On August 27, 2019, BP announced that it had agreed to sell BP Alaska and its other assets and operations in Alaska for total consideration of $5.6 billion to Hilcorp Alaska, LLC and its affiliates, which are affiliates of Houston-based Hilcorp Energy Company (collectively “Hilcorp”). On June 30, 2020, Hilcorp completed its acquisition of BP’s entire upstream business in Alaska, including BP’s interest in BP Alaska, which owned all of BP’s upstream oil and gas interest in Alaska (including oil and gas leases in the Prudhoe Bay field), and on December 18, 2020, an affiliate of Hilcorp completed its acquisition of BP’s midstream business in Alaska. On July 1, 2020, BP Alaska, a Delaware corporation, converted to a Delaware limited liability company and changed its name to Hilcorp North Slope, LLC, a wholly owned subsidiary of Hilcorp Alaska, LLC. Under the terms of the Trust Agreement, HNS is the successor to BP Alaska. For purposes of this Quarterly Report on Form 10-Q, “HNS” means (i) at all times prior to June 30, 2020, BP Alaska, and (ii) at all times after and including June 30, 2020, Hilcorp North Slope, LLC (formerly known as BP Alaska).

Pursuant to the terms of the Trust Agreement, the Trust terminates when the net revenues from the Royalty Interest for two successive years are less than $1.0 million per year. The Trust did not receive any revenues attributable to any of the four quarters of each of the years ended December 31, 2023, and 2024. Therefore, in accordance with the Trust Agreement, the Trust terminated at 11:59 PM on December 31, 2024, and Trustee has commenced the process of winding up the affairs of the Trust. See “THE TRUST – Termination of the Trust” in Part I, Item 1 of the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024 (the “2024 Annual Report”).

Upon the termination of the Trust, the Trust Agreement requires the Trustee to sell for cash all the assets of the Trust (other than cash). Under the Trust Agreement, HNS had an option to purchase the Trust assets at a price equal to the greater of (i) the fair market value of the Trust property as set forth in an opinion of an investment banking firm, commercial banking firm or other entity qualified to give an opinion as to the fair market value of the assets of the Trust on the date of termination, or (ii) $11,641,600, which represents 21,400,000 outstanding Units as of December 31, 2024 multiplied by $0.544 (the closing price of the Units on the New York Stock Exchange on December 31, 2024, the termination date of the Trust), exercisable within 30 days of receipt of the opinion.

Following termination of the Trust, the Trustee engaged RedOaks Energy Advisors, LLC (“RedOaks”) as its advisor to provide the opinion to HNS in accordance with the Trust Agreement, and to assist with the marketing and sale of the Trust’s assets. The RedOaks opinion reflected a de minimis valuation for the Trust assets solely as of the termination date and was prepared for the purpose of determining the option value in accordance with the Trust Agreement; however, such opinion was not intended to reflect current potential asset valuations or for use in connection with asset bids, and will not be updated for such use. On June 2, 2025, HNS informed the Trustee that it declined to exercise its option to purchase the Trust assets.

Since HNS declined to exercise its purchase option, the Trust Agreement requires the Trustee to sell the Trust assets on terms and conditions approved by the vote of holders of 60% of the outstanding Units, unless the Trustee determines that it is not practicable to submit the matter to a vote of the Unit holders and the sale is made at a price at least equal to the fair market value of the Trust assets as set forth in the third-party opinion and on terms and conditions deemed commercially reasonable by the third-party valuing the Trust assets. Therefore, RedOaks commenced a sale process on behalf of the Trust. Initial bids for the Trust assets were due on July 29, 2025, and updated bids were due on August 5, 2025. The Trust and RedOaks are reviewing the bid proposals RedOaks received and intend to proceed to negotiating the terms of a potential sale agreement with the highest bidder. The Trustee cannot predict the timing of the closing of a potential sale of the assets and cannot provide any assurance that a sale will be concluded.

The information in this report relating to the Prudhoe Bay Unit, the calculation of royalty payments and certain other matters has been furnished to the Trustee by HNS, and the Trustee is entitled to rely on the accuracy of such information in accordance with the Trust Agreement.

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Recent Developments

The average daily closing WTI price was below the “break-even” price for the quarter ended June 30, 2025, resulting in a negative value for the payment calculation for the quarter. However, the payment with respect to the Royalty Interest for any calendar quarter may not be less than zero.

The Trustee paid all accrued expenses of the Trust through June 30, 2025, totaling $588,418, from the cash reserve.

For the three months ended June 30, 2025, the Per Barrel Royalty was calculated based on the following information:

Average WTI Price		$	63.95
Average Adjusted Chargeable Costs		$	99.63
Average Production Taxes		$	2.15
Average Per Barrel Royalty		$	(37.83	)
Average Net Production (mb/d)			63.3

Forward-Looking Statements

Various sections of this report contain forward-looking statements (that is, statements anticipating future events or conditions and not statements of historical fact) within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Words such as “anticipate,” “estimates,” “expect,” “believe,” “intend,” “likely” “plan”, “predict” or “project,” and “should,” “would,” “could,” “potentially,” “possibly” or “may,” and other words that convey uncertainty of future events or outcomes are intended to identify forward-looking statements. Forward-looking statements in this report are subject to a number of risks and uncertainties beyond the control of the Trust. These risks and uncertainties include matters such as future changes in oil prices, oil production levels, production charges and costs, changes in expenses of the Trust, cash reserve levels, the timing and outcome of winding up the Trust and the Trust asset sale process, the liquidity of the trading market for the Units on OTC Pink, economic conditions, domestic and international political events and developments in major oil producing regions, especially in the Middle East and Russia, legislation and regulation, the effect of tariffs, international hostilities, war, including Russia’s war with Ukraine and Israel’s war with Hamas, potential escalations and geographic expansions and the international responses to these events, including the imposition of international sanctions and increase in international military intervention, and public health crises.

The actual results, performance and prospects of the Trust could differ materially from those expressed or implied by forward-looking statements. Descriptions of some of the risks that could affect the future performance of the Trust appear in Part 1, Item 1A, “RISK FACTORS,” of the 2024 Annual Report) and Part II, Item 1A. “Risk Factors”, of this Form 10-Q.

There may be additional risks of which the Trustee is unaware or which it currently deems immaterial.

In the light of these risks, uncertainties and assumptions, you should not rely unduly on any forward-looking statements. Forward-looking events and outcomes discussed in the 2024 Annual Report and in this Form 10-Q and the Trust’s other reports may not occur or may turn out differently. The Trustee undertakes no obligation to update forward-looking statements after the date of this report, except as required by law, and all such forward-looking statements in this report are qualified in their entirety by the preceding cautionary statements.

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Liquidity and Capital Resources

Background. The Trust is a passive entity. The Trustee’s activities are limited to collecting and distributing the revenues from the Royalty Interest and paying liabilities and expenses of the Trust. Generally, the Trust has no source of liquidity and no capital resources other than the revenues attributable to the Royalty Interest that it receives from time to time. See the discussion under “THE ROYALTY INTEREST” in Part I, Item 1 of the 2024 Annual Report for a description of the calculation of the Per Barrel Royalty, and the discussion under “THE PRUDHOE BAY UNIT AND FIELD – Reserve Estimates” in Part I, Item 1 of the 2024 Annual Report for information concerning the estimated future net revenues of the Trust. However, the Trust Agreement gives the Trustee power to borrow, establish a cash reserve, or dispose of all or part of the Trust property under limited circumstances. See the discussion under “THE TRUST – Sales of Royalty Interest; Borrowings and Reserves” in Part I, Item 1 of the 2024 Annual Report.

Cash Reserve. In July 1999, the Trustee established a cash reserve to provide liquidity to the Trust during future periods in which the Trust does not receive sufficient revenues from the Royalty Interest. The Trustee has drawn funds from the cash reserve account during the quarters in which the quarterly revenues received by the Trust did not exceed the liabilities and expenses of the Trust and has replenished and added to the reserve from deductions from quarterly distributions made to Unit holders during periods when the Trust received revenues from the Royalty Interest.

Due in part to the economic impacts of the COVID-19 pandemic in 2020, the markets experienced a decline in oil prices in response to oil demand concerns and global storage considerations. As a result of, among other things, lower oil prices and the increase in Chargeable Costs, the Trust received no revenues from the Royalty Interest attributable to the four quarters of 2020 or the first quarter of 2021. Consequently, the Trust was unable to make any additions to the funds on deposit in the cash reserve account since the January 2020 distribution made for revenues from the Royalty Interest attributable to the fourth quarter of 2019. In December 2020, the remaining funds on deposit in the cash reserve were insufficient to pay the Trustee’s Administrative Expenses in 2020 and the Trustee made a demand for indemnity and reimbursement of expenses upon HNS in accordance with the Trust Agreement in the amount of $537,835, representing the Trust’s unpaid expenses through December 18, 2020.

Following the receipt of the indemnity payment from HNS in December 2020, the Trust continued to accrue Administrative Expenses but did not receive any revenues from the Royalty Interest until July 2021, when the Trust received a quarterly payment of approximately $3.2 million attributable to the quarter ended June 30, 2021.

In July 2021, the Trustee increased the Trustee’s existing cash reserve of $1.27 million by $500 thousand, funding the full amount of the cash reserve from the royalty payment attributable to the second quarter of 2021. In October 2021, the Trust increased the Trustee’s existing cash reserve to $6.0 million, which was fully funded from the royalty payment attributable to the third quarter of 2021.

The total amount added to the cash reserve took into account that (i) the Trust had not received any revenues attributable to 2020 or the first quarter of 2021 and therefore had been unable to make any additions to the cash reserve for five quarters, (ii) the likelihood of future revenue from the Royalty Interest, (iii) the increase in Trust Administrative Expenses in 2020, (iv) the reset of the earliest potential termination date of the Trust, and (v) the expected expenses associated with the future termination of the Trust. As previously disclosed by the Trust, the Trustee increased and funded the cash reserve to a level it believes will be sufficient to provide funding to pay the Administrative Expenses for a two-year period commencing when the sum of the net revenues from the Royalty Interest for two successive years are less than $1.0 million per year, and to carry out an orderly termination of the Trust as set forth in Article IX of the Trust Agreement. Depending on the facts and circumstances, the expenses of the termination process may include, without limitation, costs related to a professional evaluation of the value of the Royalty Interest, any and all other costs and expenses necessary to terminate the Trust, sell the Trust assets and provide for the orderly distribution of the remaining proceeds to the Unit holders, the costs of one or more consent solicitations of the Unit holders, legal fees and expenses, and all other professional services necessary to comply with the requirements of the Trust termination process and public company reporting obligations.

Given the lack of revenue from the Royalty Interest, and the ongoing expenses of operating the Trust through the termination process, the Trustee previously determined to withhold amounts necessary, when and if received by the Trust, to maintain the cash reserve at a target level of approximately $6.0 million. Considering that the Trust is now in wind-down, the Trustee does not expect to maintain the cash reserve at that level and expects to reevaluate the cash reserve target in the event of any future payment from the Royalty Interest and potential proceeds from the sale of the Trust assets. Even if the Trustee determines to reduce the cash reserve target level, if the Trust receives net revenues from the Royalty Interest in any quarter during 2025, it is possible that Unit holders will not receive a distribution on outstanding Units during such periods, because the Trust may withhold funds from any such revenue to first pay accrued Administrative Expenses and retain funds in the cash reserve, before distributing any funds to Unit holders. There can be no assurance that WTI prices will be at levels sufficient to result in revenues to the Trust in any future quarter.

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Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of accrued Administrative Expenses, expenses incurred in connection with the winding up of the Trust and future known, anticipated or contingent expenses or liabilities eventually will be distributed to Unit holders, together with any interest earned on the funds. Any amounts set aside for the cash reserve are invested by the Trustee in U.S. government or agency securities secured by the full faith and credit of the United States, or mutual funds investing in such securities.

Results of Operations

Relatively modest changes in oil prices significantly affect the Trust’s revenues and results of operations. Crude oil prices are subject to significant changes in response to fluctuations in the domestic and world supply and demand and other market conditions as well as the world political situation, particularly the invasion of Ukraine by Russia and the conflicts in the Middle East, as it affects OPEC+ and other oil producing countries. The effect of changing political and economic conditions on the demand and supply for energy throughout the world and future prices of oil cannot be accurately projected.

Royalty revenues are generally received on the Quarterly Record Date (generally the fifteenth day of the month) following the end of the calendar quarter in which the related Royalty Production occurred. The Trustee, to the extent possible, pays all expenses of the Trust for each quarter on the Quarterly Record Date on which the revenues for the quarter are received. For the statement of cash earnings and distributions, revenues and Trust expenses are recorded on a cash basis and, as a result, distributions shown for the three-month periods ended June 30, 2025 and 2024, respectively, are attributable to HNS’s operations during the three-month periods ended March 31, 2025 and 2024, respectively.

Under the terms of the Conveyance of the Royalty Interest to the Trust, the Per Barrel Royalty for any day is the WTI Price for the day less the sum of (i) Chargeable Costs multiplied by the Cost Adjustment Factor and (ii) Production Taxes. The discussion under the captions “THE TRUST – Trust Property” and “THE ROYALTY INTEREST” in Part 1, Item 1 of the 2024 Annual Report explains the meanings of the terms “Conveyance,” “Royalty Interest,” “Per Barrel Royalty,” “WTI Price, “Chargeable Costs” and “Cost Adjustment Factor” and should be read in conjunction with this report.

“Royalty Production” for each day in a calendar quarter is 16.4246% of the first 90,000 barrels of the actual average daily net production of oil and condensate for the quarter from the proved reserves allocated to the Trust. When HNS’s average net production of oil and condensate per quarter from the 1989 Working Interests exceeds 90,000 barrels a day, the principal factors affecting the Trust’s revenues and distributions to Unit holders are changes in WTI Prices, scheduled annual increases in Chargeable Costs, changes in the Consumer Price Index and changes in Production Taxes. The Trust’s revenues have also been affected by decreases in production from the 1989 Working Interests. HNS’s net production of oil and condensate allocated to the Trust from proved reserves was less than 90,000 barrels per day on an annual basis during each year from 2020 through 2024 and for the first and second quarters of 2025. The Trustee has been advised that HNS expects that average net production allocated to the Trust from the proved reserves will be less than 90,000 barrels a day on an annual basis in future years. This is due to the normal declining production rate from the Prudhoe Bay field and variance in the impact of planned and unplanned maintenance programs.

The “break-even” WTI Price (the price at which all taxes and prescribed deductions are equal to the WTI Price) changes over time primarily as a result of changes in the Cost Adjustment Factor, which is based on the Consumer Price Index published for the most recently past February, May, August or November and Production Taxes, as Chargeable Costs remain constant for the calendar year. Additionally, as WTI Prices change, so do the Production Taxes and prescribed deductions, potentially increasing or decreasing the “break-even” WTI Price. The quarterly royalty payment by HNS to the Trust is the sum of the individual revenues attributed to the Trust as calculated each day during the quarter. Any single calculation of a calendar day will not reflect the value of the dividend paid to the Trust for the quarter, nor will it reflect the estimated future value of the Trust.

From the beginning of the first quarter of 2025 through March 31, 2025, the closing WTI crude oil spot price fluctuated between a high of $80.04 per barrel on January 15, 2025 and a low of $66.03 per barrel on March 10, 2025, and on average was below the “break-even” level necessary for the Trust to receive a Per Barrel Royalty for the first quarter of 2025.

From the beginning of the second quarter of 2025 through June 30, 2025, the closing WTI crude oil spot price fluctuated between a high of $75.14 per barrel on June 18 and June 19, 2025 and a low of $57.13 per barrel on May 5, 2025, and on average was below the “break-even” level necessary for the Trust to receive a Per Barrel Royalty for the second quarter of 2025.

Whether the Trust will be entitled to future net revenue from the Royalty Interest during the remainder of 2025 will depend on, among other things, WTI Prices prevailing during the remainder of 2025. While future oil prices cannot be accurately projected, the U.S. Energy Information Administration forecasts in its Short-Term Energy Outlook, released on July 8, 2025, that WTI prices will average $64.69 per barrel in the third quarter of 2025 and $60.02 per barrel in the fourth quarter of 2025. There can be no assurance that WTI prices for the third quarter of 2025 or beyond will be at or above these projected prices or that WTI prices will be above the “break even” level necessary for the Trust to receive a Per Barrel Royalty in any future quarter.

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HNS estimates Royalty Production from the 1989 Working Interests for purposes of calculating quarterly royalty payments to the Trust because complete actual field production data for the preceding calendar quarter generally is not available by the Quarterly Record Date. To the extent that average net production from the 1989 Working Interests is below 90,000 barrels per day, calculation by HNS of actual Royalty Production data may result in revisions of prior Royalty Production estimates. Revisions by HNS of its Royalty Production calculations may result in quarterly royalty payments by HNS which reflect adjustments for overpayments or underpayments of royalties with respect to prior quarters. Such adjustments, if material, may adversely affect certain Unit holders who buy or sell Units between the Quarterly Record Dates for the Quarterly Distributions affected.

The quarterly distribution received by the Trust from HNS in January 2023 attributable to the fourth quarter of 2022 included an overpayment of $13,279. There has been no quarterly distribution to the Trust since the quarterly distribution received in January 2023, and therefore the overpayment remains outstanding and will be deducted from any future quarterly distribution or the final distribution to Unit holders on the completion of the winding up process. Because the statements of cash earnings and distributions of the Trust are prepared on a modified cash basis, royalty revenues for the three-month periods ended June 30, 2025 and 2024 reflect the amount of the adjustments with respect to the earlier fiscal periods.

The following table summarizes the factors that determined the Per Barrel Royalty used to calculate payments due to the Trust, if any, in April and January 2025 and 2024. See Note 1 of Notes to Financial Statements (Unaudited) in Item 1. The information in the table has been furnished to the Trust by HNS.

						Data for Quarter Average
Royalty Payment in Month		Based on Data for Quarter Ended				Average WTI Price				Chargeable Costs				Cost Adjustment Factor				Adjusted Chargeable Costs				Average Production Taxes				Average Per Barrel Royalty				Average Net Production (mb/d)
April 2025			03/31/25			$	71.50			$	40.25				2.4569			$	98.89			$	2.46			$	(29.85	)			65.6
Jan. 2025			12/31/24			$	70.32			$	37.50				2.4293			$	91.10			$	2.42			$	(23.19	)			64.6
April 2024			03/31/24			$	77.01			$	37.50				2.3895			$	89.61			$	2.69			$	(15.28	)			66.8
Jan. 2024			12/31/23			$	78.47			$	34.75				2.3643			$	82.16			$	2.75			$	(6.44	)			67.9

Three Months Ended June 30, 2025 Compared to Three Months Ended June 30, 2024

Trust royalty revenues, if any, received during the second quarter of the fiscal year are based on Royalty Production during the first quarter of the fiscal year. The following table shows the changes between the three months ended March 31, 2025 and the three months ended March 31, 2024 in the factors that determined the Per Barrel Royalties used to calculate royalty payments, if any, for the quarters ended June 30, 2025 and 2024.

						Increase (decrease)
		Three Months Ended 3/31/2025				Amount				Percent				Three Months Ended 3/31/2024
Average WTI Price		$	71.50			$	(5.51	)			(7.2	)		$	77.01
Adjusted Chargeable Costs		$	98.89			$	9.28				10.4			$	89.61
Average Production Taxes		$	2.46			$	(0.23	)			(8.6	)		$	2.69
Average Per Barrel Royalty (paid)		$	(29.85	)		$	(14.57	)			(95.4	)		$	(15.28	)
Average net production (mb/d)			65.6				(1.2	)			(1.8	)			66.8

The average WTI Price for the first quarter of 2025 decreased 7.2% compared to the average WTI Price for the first quarter of 2024. The increase in the Consumer Price Index used to calculate the Cost Adjustment Factor, as well as the scheduled increase in Chargeable Costs from $37.50 in calendar year 2024 to $40.25 in calendar year 2025, resulted in a 10.4% percent increase in Adjusted Chargeable Costs for the three months ended March 31, 2025. Production Taxes decreased 8.6% as a result of the decrease in the average WTI Price, and Production Taxes were calculated on the basis of the minimum tax under Alaska law and the 2014 Letter Agreement Amendment. See Note 6 of Notes to Financial Statements (Unaudited) in Item 1 above. The Average Per Barrel Royalty for the period decreased by $14.57, remaining at a negative value, primarily as a result of the increase in Adjusted Chargeable Costs and decrease in Average WTI Price during the first quarter of 2025 as compared to the first quarter of 2024. However, the payment with respect to the Royalty Interest for any calendar quarter may not be less than zero. The average net production from the 1989 Working Interest for the two reporting periods declined by 1.8%. This decrease was due to the naturally declining production rate from the Prudhoe Bay field.

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The following table shows the changes to the Trust’s revenues received and distributions paid during the quarter ended June 30, 2025, as compared to the same period in 2024 resulting from the factors in the table above, as well as changes in Administrative Expenses.

						Increase (decrease)
		Three Months Ended 6/30/2025				Amount				Percent				Three Months Ended 6/30/2024
						(Dollar amounts in thousands)
Royalty revenues		$	—			$	—				—			$	—
Cash earnings (loss)		$	(552	)		$	(58	)			(11.7	)		$	(494	)
Cash distributions		$	—			$	—				—			$	—
Administrative expenses		$	588			$	32				5.8			$	556

There were no royalty revenues distributed in either the second quarter of 2025 or the second quarter of 2024. The period-to-period increase in cash losses is due to payments of Administrative Expenses being made solely from the cash reserve. The increase in Administrative Expenses paid during the three months ended June 30, 2025, is primarily due to increases in fees charged by the Trust’s service providers. The Trust Corpus decreased at the end of the three months ended June 30, 2025, as compared to the same period in 2024, due to the payment of the Trust’s Administrative Expenses from the cash reserve.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

Trust royalty revenues received during the first six months of the fiscal year are based on the Royalty Production during the first quarter of the fiscal year and the fourth quarter of the preceding fiscal year. The following table shows the changes between the six months ended March 31, 2025 and the six months ended March 31, 2024, in the factors that determined the Per Barrel Royalties used to calculate the Royalty Payment received by the Trust during the six months ended June 30, 2025 and 2024.

						Increase (decrease)
		Six Months Ended 3/31/2025				Amount				Percent				Six Months Ended 3/31/2024
Average WTI Price		$	70.90			$	(6.85	)			(8.8	)		$	77.75
Adjusted Chargeable Costs		$	94.95			$	9.11				10.6			$	85.84
Average Production Taxes		$	2.44			$	(0.28	)			(10.3	)		$	2.72
Average Per Barrel Royalty (paid)		$	(26.49	)		$	(15.68	)			(145.1	)		$	(10.81	)
Average net production (mb/d)			65.1				(2.3	)			(3.4	)			67.4

The average WTI Price for the six-month period in 2025 decreased 8.8% compared to the average WTI Price for the six-month period in 2024. The increase in the Consumer Price Index used to calculate the Cost Adjustment Factor, as well as the scheduled increase in Chargeable Costs from $37.50 in calendar year 2024 to $40.25 in calendar year 2025, resulted in a 10.6% increase in Adjusted Chargeable Costs for the six month period. Production Taxes decreased 10.3% as a result of the decrease in the average WTI Price, and Production Taxes were calculated on the basis of the minimum tax under Alaska law and the letter agreement by and between BP Alaska and the Trustee, dated January 15, 2014. See Note 6 of Notes to Financial Statements (Unaudited) in Item 1 above. The Average Per Barrel Royalty paid decreased by $15.68, remaining a negative value, primarily as a result of the decrease in the Average WTI Price during the six month period and increase in the Adjusted Chargeable Costs between calendar year 2025 and calendar year 2024. As provided in the Trust Agreement, the payment with respect to the Royalty Interest for any calendar quarter may not be less than zero. The average net production from the 1989 Working Interest for the two reporting periods declined by 3.4%. This decrease was due to the naturally declining production rate from the Prudhoe Bay field.

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The following table shows the changes to the Trust’s revenues received and distributions paid during the six months ended June 30, 2025, as compared to the same period in 2024 resulting from the factors in the table above, as well as changes in Administrative Expenses.

						Increase (decrease)
		Six Months Ended 6/30/2025				Amount				Percent				Six Months Ended 6/30/2024
						(Dollar amounts in thousands)
Royalty revenues		$	—			$	—				—			$	—
Cash earnings (loss)		$	(1,042	)		$	277				36.2			$	(765	)
Cash distributions		$	—			$	—				—			$	—
Administrative expenses		$	1,120			$	226				25.3			$	894

There were no royalty revenues distributed in either the six-month period ended June 30, 2025, or the six-month period ended June 30, 2024. The period-to-period increase in cash losses is due to payments of Administrative Expenses being made solely from the cash reserve. The increase in Administrative Expenses paid during the six months ended June 30, 2025, is primarily due to increases in fees charged by the Trust’s service providers. The Trust Corpus decreased at the end of the six months ended June 30, 2025, as compared to the same period in 2024 due to the payment of the Trust’s expenses from the Trust’s cash reserve.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

The Trust is a passive entity and except for the Trust’s ability to borrow money as necessary to pay liabilities of the Trust that cannot be paid out of cash on hand, the Trust is prohibited from engaging in borrowing transactions. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unit holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these investments and limitations on the types of investments which may be held by the Trust, the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unit holders to any foreign currency related market risk or invest in derivative financial instruments. The Trust has no foreign operations and holds no long-term debt instruments.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. The Trust’s internal control over financial reporting is defined as a process designed by or under the supervision of the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Trust’s financial statements for external reporting purposes in accordance with the modified cash basis of accounting. The Trust’s internal control over financial reporting includes policies and procedures that pertain to maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting, and that receipts and expenditures are being made only in accordance with authorizations of the Trustee; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Trust’s assets that could have a material effect on the Trust’s financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). Based on the Trustee’s evaluation under the COSO criteria, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of June 30, 2025.

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Changes in Internal Control Over Financial Reporting

There has not been any change in the Trust’s internal control over financial reporting identified in connection with the Trustee’s evaluation of the Trust’s internal control over financial reporting that occurred during the Trust’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

None.

Item 1A. Risk Factors.

There have been no material changes from the risk factors disclosed in the Trust’s annual report on Form 10-K for the year December 31, 2024.

Item 2. Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities.

None.

Item 3. Defaults upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

Item 6. Exhibits.

31*		Rule 13a-14(a) Certification
32*		Section 1350 Certification
101		Explanatory note: An Interactive Data File is not submitted with this filing pursuant to Item 601(101) of Regulation S-K, because the Trust does not prepare its financial statements in accordance with generally accepted accounting principles as used in the United States. See Note 3 of Notes to Financial Statements (Unaudited) in Part I, Item 1.

* Filed herewith.

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SIGNATURE

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.

BP PRUDHOE BAY ROYALTY TRUST
By:		THE BANK OF NEW YORK MELLON TRUST
		COMPANY, N.A., as Trustee
By:		/s/ Elaina C. Rodgers
		Elaina C. Rodgers
		Vice President

Date: August 14, 2025

The Registrant is a trust and has no officers or persons performing similar functions. No additional signatures are available and none have been provided.

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FAQ

What were the Trust's reported cash balances at June 30, 2025 and December 31, 2024 for BPT?

The filing shows a cash-related balance of $3,117 at June 30, 2025 and $4,159 at December 31, 2024.

Did BP Prudhoe Bay Royalty Trust pay royalties in recent periods?

The filing notes that at times the Trust received no royalty payments (notably the four quarters of 2020 and Q1 2021) and that average per-barrel royalties were negative in the reported periods.

Why did the Trust Corpus decrease during the six months ended June 30, 2025?

The Trust Corpus decreased because Administrative Expenses were paid from the cash reserve, and those expenses increased due to higher fees charged by service providers.

What happened to BPT's listing on the NYSE?

The NYSE filed to delist the Units on July 17, 2025; the delisting became effective on July 27, 2025, and the Units may trade on OTC Pink.

How did production and oil prices affect Trust payments?

Average WTI prices in recent quarter-ends ranged about $70–$78 per barrel; higher Chargeable Costs and a decline in WTI reduced the Average Per Barrel Royalty and combined with a ~3.4% production decline lowered potential payments to the Trust.