BPT BP Prudhoe Bay Royalty Trust

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

or

For the quarterly period ended June 30, 2024

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)

(713) 483-6020

(Registrant’s telephone number, including area code)

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

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.

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 9, 2024, 21,400,000 Units of Beneficial Interest were outstanding.

TABLE OF CONTENTS

i

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)

(In thousands, except unit data)

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)

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)

See accompanying notes to financial statements (unaudited).

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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 BP 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).

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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.

A novel strain of coronavirus, SARS-CoV-2 (severe acute respiratory syndrome coronavirus 2), surfaced in late 2019 and spread around the world. In March 2020, the World Health Organization characterized the disease caused by the virus—COVID-19—as a pandemic. Due 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.

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 or the first and second quarter of 2024. 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 intends to continue to evaluate the adequacy of the cash reserve and may, at any time without notice to the Unit holders, increase or decrease the amount of the cash reserve due to the facts and circumstances prevailing from time to time. At this time, 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.

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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:

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, 2024 and December 31, 2023, 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, 2024 and 2023. 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, 2024 and December 31, 2023 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, 2023. The cash earnings and distributions for the interim periods presented are not necessarily indicative of the results to be expected for the full year.

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.

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.

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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.

Certain of the Royalty Payments received by the Trust in 2023 were adjusted by HNS to compensate for underpayments or overpayments of the royalties due with respect to the quarters ended prior to the dates of such payments. No adjustments to Royalty Payments by HNS were made in the second quarter of 2024 with respect to prior quarters. Average net production of crude oil and condensate from the proved reserves allocated to the Trust was less than 90,000 barrels per day during certain quarters. Royalty Payments by HNS with respect to those quarters were based on estimates by HNS of production levels because actual data was not available by the date on which payments were required to be made to the Trust. Subsequent recalculation by HNS of the Royalty Payments due based on actual production data resulted in the payment adjustments shown in the table below (in thousands).

There was no royalty payment received by the Trust in July 2024 for the quarter ended June 30, 2024.

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).

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.

Recent Developments

The average daily closing WTI price was below the “break-even” price for the quarter ended June 30, 2024, resulting in a negative value for the payment calculation for the quarter. However, 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 Trustee paid all accrued expenses of the Trust through June 30, 2024, totaling $334,765, from the cash reserve. The Trustee continues to evaluate the adequacy of the cash reserve and may increase the amount of the cash reserve in the future. See Note 2 to the Financial Statements (Unaudited) in Item 1.

For the three months ended June 30, 2024, the Per Barrel Royalty was calculated based on the following information:

The Trust did not receive Royalty Payments attributable to any quarter of 2023 or the first and second quarters of 2024 because of the decline in WTI prices, an increase in Average Adjusted Chargeable Costs and the payment of Production Taxes. The Trust will terminate if the net revenues from the Royalty Interest for two successive years are less than $1.0 million per year (unless the net revenues during the two-year period have been materially and adversely affected by a “force majeure” event). See the discussion under “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, 2023 (the “2023 Annual Report”).

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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 Trustee. 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 targets and the timing of the termination of the Trust, economic conditions, domestic and international political events and developments in major oil producing regions, especially in the Middle East and Russia, legislation and regulation, international hostilities, war, including, Russia’s war with Ukraine, Israel’s war with Hamas, including potential escalations and geographic expansions and the international responses thereto, including the imposition of international sanctions and increase in international military intervention, and public health crises (such as the COVID-19 pandemic).

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 2023 Annual Report). 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 2023 Annual Report and in this report 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.

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 2023 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 2023 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 2023 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.

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In July 2021, the Trust announced that the Trustee had determined to increase 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 determined to increase 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 takes 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. The Trustee will continue to review and reassess the adequacy of the cash reserve on an on-going basis based on the facts and circumstances at the time of such evaluations and may increase or decrease the targeted cash reserve or the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to Unit holders. As previously disclosed by the Trust, the Trustee has 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 at the time, 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.

Given the uncertainty with respect to the amount or timing of any future revenue from the Royalty Interest combined with the expenses of operating the Trust prior to termination and the limited ability to terminate the Trust in accordance with its terms, the Trustee has determined to withhold amounts necessary, when received by the Trust, to maintain the cash reserve at its current level of approximately $6.0 million at this time. This cash reserve level assumes an orderly termination of the Trust sometime in the future based on current facts and circumstances, and as the receipt of additional Royalty Payments resets that time line, the Trustee will re-evaluate the adequacy of the cash reserve balance and may increase or decrease it without notice to Unit holders. Accordingly, even if the Trust receives net revenues from the Royalty Interest in any quarter during 2024 or beyond, it is possible that Unit holders will not receive a distribution on outstanding Units during such periods, because the Trust may need to withhold funds from any such revenue to first pay accrued Administrative Expenses and to replenish or add to 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. The Trustee intends to keep the cash reserve program in place through the winding up of the Trust.

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 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, as it affects OPEC+ and other 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, 2024 and 2023, respectively, are attributable to HNS’s operations during the three-month periods ended March 31, 2024 and 2023, respectively.

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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 narrative under the captions “THE TRUST – Trust Property” and “THE ROYALTY INTEREST” in Part 1, Item 1 of the 2023 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. However, 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 2019 through 2023 and for the first and second quarters of 2024. 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 2024 through March 31, 2024, the closing WTI crude oil spot price fluctuated between a high of $83.47 per barrel on March 19, 2024 and a low of $70.38 per barrel on January 2, 2024, and on average was below the “break-even” level necessary for the Trust to receive a Per Barrel Royalty for the first quarter of 2024.

From the beginning of the second quarter of 2024 through June 30, 2024, the closing WTI crude oil spot price fluctuated between a high of $86.91 per barrel from April 5, 2024 through April 7, 2024, and a low of $73.25 per barrel on June 4, 2024, and on average was below the “break-even” level necessary for the Trust to receive a Per Barrel Royalty for the second quarter of 2024.

Whether the Trust will be entitled to future net revenue from the Royalty Interest during the remainder of 2024 will depend on, among other things, WTI Prices prevailing during the remainder of the year. While future oil prices cannot be accurately projected, the U.S. Energy Information Administration forecasts in its Short-Term Energy Outlook, released on August 6, 2024, that WTI prices will average $79.95 per barrel in the third quarter of 2024 and $81.47 per barrel in the fourth quarter of 2024. There can be no assurance that WTI prices for the third quarter of 2024 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 future periods.

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 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. 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, 2024 and 2023 reflect the amount of the adjustments with respect to the earlier fiscal periods.

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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 2024 and 2023. 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.

Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023

Trust royalty revenues 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, 2024 and the three months ended March 31, 2023 in the factors that determined the Per Barrel Royalties used to calculate the Royalty Payment received by the Trust during the quarters ended June 30, 2024 and 2023.

The average WTI Price for the first quarter of 2024 increased 1.1% compared to the average WTI Price for the first quarter of 2023. The increase in the Consumer Price Index used to calculate the Cost Adjustment Factor, as well as the scheduled increase in Chargeable Costs from $34.75 in calendar year 2023 to $37.50 in calendar year 2024, resulted in an 11.3% percent increase in Adjusted Chargeable Costs for the three months ended March 31, 2024. Production Taxes increased 0.7% as a result of the increase 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 $8.28, remaining at a negative value, primarily as a result of the increase in Adjusted Chargeable Costs during the first quarter of 2024 as compared to the first quarter of 2023. 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 5.0%. 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, 2024, as compared to the same period in 2023 resulting from the factors in the table above, as well as changes in Administrative Expenses.

There were no royalty revenues distributed in either the second quarter of 2024 or the second quarter of 2023. The period-to-period decreases in cash earnings and cash distributions are due to the non-payment of the Per Barrel Royalty as a result of the increase in Adjusted Chargeable Costs that prevailed during the three months ended June 30, 2024, compared to the same period in 2023. The decrease in Administrative Expenses paid during the three months ended June 30, 2024, is primarily due to differences in the timing of invoices. The Trust Corpus decreased at the end of the three months ended June 30, 2024, as compared to the same period in 2023 due to the payment of the Trust’s expenses from the cash reserve instead of from the Per Barrel Royalty in the prior period.

Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023

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, 2024 and the six months ended March 31, 2023, 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, 2024 and 2023.

The average WTI Price for the six-month period in 2024 decreased 2.1% compared to the average WTI Price for the six-month period in 2023. The increase in the Consumer Price Index used to calculate the Cost Adjustment Factor, as well as the scheduled increase in Chargeable Costs from $34.75 in calendar year 2023 to $37.50 in calendar year 2024, resulted in an 11.6% percent increase in Adjusted Chargeable Costs for the six month period. Production Taxes decreased 2.9% 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 $10.50, 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 2024 and calendar year 2023. 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 4.1%. This decrease was due to the naturally declining production rate from the Prudhoe Bay field.

13

The following table shows the changes to the Trust’s revenues received and distributions paid during the six months ended June 30, 2024, as compared to the same period in 2023 resulting from the factors in the table above, as well as changes in Administrative Expenses.

The period-to-period decreases in royalty revenues, cash earnings and cash distributions are due to the decline in average WTI Prices and the increase in Adjusted Chargeable Costs and the decline in average net production that prevailed during the six months ended June 30, 2024, compared to the same period in 2023. The increase in Administrative Expenses paid during the six months ended June 30, 2024, reflects an increase in fees payable by the Trust, primarily due to differences in the timing of invoices and increases in fees charged by the Trust’s service providers. The Trust Corpus decreased at the end of the six months ended June 30, 2024, as compared to the same period in 2023 due to the payment of the Trust’s expenses from the Trust’s cash reserve instead of from the Per Barrel Royalty in the prior period, slightly offset by an increase in interest income.

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.

14

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, 2024.

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, 2023.

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.

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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.

Date: August 9, 2024

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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EXHIBIT 31

RULE 13a-14(a)/15d-14(a) CERTIFICATION

I, Elaina C. Rodgers, certify that:

Date: August 9, 2024

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-

OXLEY ACT OF 2002

In connection with the Quarterly Report of BP Prudhoe Bay Royalty Trust (the “Registrant”), on Form 10-Q for the quarter ended June 30, 2024, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

Date: August 9, 2024