UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM10-K

For the Fiscal Year ended December 31, 20182020

OR

Commission File Number1-10243

BP PRUDHOE BAY ROYALTY TRUST

(Exact name of registrantregistration as specified in its charter)

(713) 483-6020

(Registrant’s telephone number, including area code: (713)483-6020code)

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

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☐    No  ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ☐    No  ☒

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 RegulationS-T (17 CFR § 232.405) 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 if disclosure of delinquent filers pursuant to Item 405 of RegulationS-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form10-K or any amendment to this Form10-K.  ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” accelerated filer” and“accelerated filer,” “smaller reporting company”company,” and “emerging growth company” in Rule12b-2 of the Exchange Act. (Check one):

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange ActAct).    Yes  ☐    No  ☒

The aggregate market value of Units held by nonaffiliates (computed by reference to the closing sale price in New York Stock Exchange transactions on June 29, 201830, 2020 (the last business day of the registrant’s most recently completed second fiscal quarter)) was approximately $639,860,000.$71,262,000.

As of March 1, 2019,3, 2021, 21,400,000 Units of Beneficial Interest were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

NoneDocuments incorporated by reference: NONE

TABLE OF CONTENTS

i

ii

PART I

INTRODUCTION

BP Prudhoe Bay Royalty Trust (the “Trust”“Trust”) was created as a Delaware business trust by the BP Prudhoe Bay Royalty Trust Agreement dated as of February 28, 1989 (the “Trust Agreement”“Trust Agreement”) among The Standard Oil Company (“Standard Oil”Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”Alaska”), The Bank of New York Mellon (formerly named The Bank of New York) (“BNYM”), as trustee, and F. James Hutchinson,co-trustee (BNY Mellon Trust of Delaware, formerly named The Bank of New York (Delaware), successorco-trustee). At the time of the execution of the Trust, BP Alaska and Standard Oil are wholly ownedwere wholly-owned subsidiaries of BP p.l.c. (“BP”BP”).

EffectiveOn 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. Hilcorp and its affiliates employ approximately 1,400 full-time employees in Alaska. Under the terms of the Trust Agreement, HNS is the successor to BP Alaska. For purposes of this Annual Report on Form 10-K, “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 ofBP Alaska).

On December 15, 2010, The Bank of New York Mellon (“BNYM”)BNYM resigned as trustee under the Trust Agreement and BP Alaska appointed The Bank of New York Mellon Trust Company, N.A. (the “Trust Company”“Trust Company”) to succeed BNYM as trustee. The Trust Company accepted its appointment and assumed all rights, titles, duties, powers and authority formerly held and exercised by BNYM under the Trust Agreement. The corporate trust office of the Trust Company (which we refer to hereafter as the “Trustee”“Trustee”) at which the affairs of the Trust are administered is located at 601 Travis Street, Floor 16, Houston, Texas, 77002 and its telephone number at that address is (713)483-6020.

The Trust electronically files annual reportsmaintains an Internet website at https://bpt.q4web.com/home/default.aspx. The Trust’s Annual Report on Form10-K, quarterly reportsQuarterly Reports on Form10-Q and when certain events require them, current reportsCurrent Reports on Form8-K, with the Securities and Exchange Commission (“SEC”). The public may read and copyas well as any materials filed by the Trust with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers (including the Trust) that file electronically with the SEC. The address of the SEC’s website ishttp://www.sec.gov.

The Trust does not maintain an Internet website, but certain information concerning the Trust and the Trust Units may be obtained from the BusinessWire website at the following page location:http://bpt.investorhq.businesswire.com. The Trustee will provide paper or electronic copies of the Trust’s reports on Form10-K, Form10-Q and Form8-K, and amendments to those reports, are available free of charge upon requestthrough the Trust’s website as soon as reasonably practicable after the Trustit files them with, or furnishes them to, the SEC. Requests for copiesThe SEC maintains a website at www.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including the Trust. Information contained on, or that can be accessed through, the Trust’s website is not incorporated by reference into this Annual Report on Form 10-K, and you should not consider information on the Trust’s website to be part of reports may be made by mail to:this Annual Report on Form 10-K. The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 16, Houston, TX 77002, Attention: Global Corporate Trust – Corporate Finance; by telephone to: (713)483-6020; or bye-mail to: elaina.c.rodgers@bnymellon.com.has included its website address as an inactive textual reference only.

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 BP Alaska.HNS, and the Trustee is entitled to rely on the accuracy of such information in accordance with the Trust Agreement.

Forward-Looking Statements

Various sections of this report containforward-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,” “expect,” “believe,” “intend,” “plan” 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 such matters as future changes in oil prices, oil production levels, production charges and costs, economic activity, domestic and international political events and developments, legislation and regulation, COVID-19,and certain changes in expenses of the Trust.

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 the following Item 1A, “RISK FACTORS,” and elsewhere in this report. There may be additional risks of which the Trustee is unaware or which are currently deemed 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 this report 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.

THE TRUST

Trust Property

The property of the Trust consists of an overriding royalty interest (the “Royalty Interest”“Royalty Interest”) and cash and cash equivalents held by the Trustee from time to time. The Royalty Interest entitles the Trust to a royalty on 16.4246% of the lesser of (i) the first 90,000 barrels¹ (the term “barrel” is a unit of measure of petroleum liquids equal to 42 United States gallons corrected to 60 degrees Fahrenheit temperature) of the actual average actual daily net production of crude oil and condensate per quarter from the working interest of BP Alaska (as predecessor to HNS) as of February 28, 1989, in the Prudhoe Bay oil field located on the North Slope in Alaska or (ii) the actual average actual daily net production of crude oil and condensate per quarter from that working interest. The Prudhoe Bay field is one of four contiguous North Slope oil fields that are operated by BP AlaskaHNS and are known collectively as the “Prudhoe“Prudhoe Bay Unit.Unit.” The Royalty Interest was conveyed to the Trust by an Overriding Royalty Conveyance dated February 27, 1989, from BP Alaska (as predecessor to HNS) to Standard Oil and a Trust Conveyance dated February 28, 1989, from Standard Oil to the Trust. Copies of the Overriding Royalty Conveyance and the Trust Conveyance are filed with the SEC as exhibits to this report. The Overriding Royalty Conveyance and the Trust Conveyance are referred to collectively in this report as the “Conveyance.“Conveyance.”

The Royalty Interest is anon-operationalnon-operating interest in minerals. The Trust does not have the right to take oil and gas in kind, nor does it have any right to take over operations or to share in any operating decision with respect to BP Alaska’sHNS’s working interest in the Prudhoe Bay field. BP AlaskaHNS is not obligated to continue to operate any well or maintain or attempt to maintain in force any portion of its working interest when, in its reasonable and prudent business judgment, the well or interest ceases to produce or is not capable of producing oil or gas in paying quantities.

EmployeesHuman Capital

The Trust has no employees. All administrative functions of the Trust are performed by the Trustee.Trustee, in accordance with the terms of the Trust.

Duties and Powers of the Trustee

The duties of the Trustee are specified in the Trust Agreement and the laws of the State of Delaware. BNY Mellon Trust of Delaware has been appointedco-trustee in order to satisfy the Delaware Statutory Trust Act’s requirement that the Trust have at least one trustee resident in, or which has its principal place of business in, Delaware. However, 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. A copy of the Trust Agreement is filed with the SEC as an exhibit to this report.

The basic function of the Trustee is to collect income from the Royalty Interest, to perform all necessary filing and reporting obligations of the Trust, to pay all fees, expenses, costs, charges and obligations of the Trust from the Trust’s income and assets, and to pay available cash to Unit holders. Because of the passive nature of the Trust’s assets and the restrictions on the power of the Trustee to incur obligations, the only liabilities that the Trust normally incurs in the conduct of its operations areinclude, without limitation, the Trustee’s fees and routine administrative fees, expenses, charges and costs, including accounting, engineering, legal, financial advisory, and other professional fees.fees (“Administrative Expenses”).

The Trust Agreement grants the Trustee only the rights and powers necessary to achieve the purposes of the Trust. The Trust Agreement prohibits the Trust from engaging in any business or commercial activity or, with certain exceptions, any investment activity and from using any assets of the Trust to acquire any oil and gas lease, royalty or other mineral interest.

The Trustee is entitled to a fee for its services and to be indemnified outreimbursed for Administrative Expenses from the Royalty Payments, and the cash reserve, and other sources available to the Trustee, including indemnification and sale of Trust assets. The Trustee may also be reimbursed for liabilities of the assets Trust through a loan in accordance with Section 6.06of the Trust Agreement, or a sale of assets in accordance with Section 6.02 of the Trust Agreement, in each case under limited circumstances and subject to specified conditions, if the Royalty Payments or the cash reserve are insufficient to reimburse the Trustee for any liability or loss incurred by it in the performance of its duties unlessduties. The Trust Agreement also provides that the loss results from its negligence, bad faith or fraud or from expenses incurred in carrying out its duties that exceed the compensationTrustee, subject to certain exceptions, shall be indemnified by, and reimbursement to which it is entitled to receive reimbursement from (i) HNS (1) whenever the assets of the Trust are insufficient or not permitted by applicable law to provide such indemnity and (2) after the termination of the Trust to the extent that the Trustee did not have actual knowledge, or should not have reasonably known, of a potential claim against the Trustee for which a reserve could have been established and used to satisfy such claim prior to the final distribution of assets of the Trust upon its termination or to the extent any such reserve was insufficient and (ii) the assets of the Trust during any other period, against and from any and all liability, expense, claim, damage or loss (including reasonable legal fees and expenses) incurred by it, individually or as Trustee, in the administration of the Trust and the Trust assets.

HNS has also agreed to indemnify the Trustee, individually and as Trustee, and the Trust against certain liabilities under the Trust Agreement.federal securities laws.

Sales of Royalty Interest; Borrowings and Reserves

With certain exceptions, the Trustee may sell all or part of the Royalty Interest or an interest therein only if authorized to do so by vote of the holders of 60% of the Units outstanding. Under certain circumstances, such as a sale of assets, the Trustee may sell all or part of the Royalty Interest or an interest therein without a vote of the Unit holders. However, if the sale is made in order to pay specific liabilities of the Trust then due and involves a part, but not all or substantially all, of the Trust properties,assets, the sale only needs to be approved by the vote of holders of a majority of the Units.Units outstanding. Any sale of Trust propertiesassets must be for cash unless otherwise authorized by the Unit holders. The Trustee is obligated to distribute the available net proceeds of any such sale to the Unit holders after satisfaction of the Trust’s outstanding and unpaid liabilities (which would include, without limitation, any fees, costs, expenses, charges and Administrative Expenses), and establishing or increasing reserves for the future liabilities of the Trust.

The Trustee has the power to borrow on behalf of the Trust or to sell Trust assets to pay liabilities of the Trust and to establish a reserve for the payment of liabilities without the consent of the Unit holders under the following circumstances:

In order for the Trustee to borrow, sell assets to pay Trust liabilities or establish a reserve for Trust liabilities, the Trustee must receive an unqualified written legal opinion that the contemplated action will not adversely affect the classification of the Trust as a “grantor trust” for federal income tax purposes or cause the income from the Trust to be treated as unrelated business taxable income for federal income tax purposes. If the Trustee is unable to obtain the required legal opinion, it still may proceed with the borrowing or sale, or establish the reserve, if it determines that the failure to do so will be materially detrimental to the Unit holders considered as a whole.

The Trustee maintainsIn order to ensure that the Trust had the ability to pay future expenses, the Trust established a $1,000,000 cash reserve account in July 1999. The cash reserve account has been funded from periodic deductions from the Royalty Payments. These deductions were intended to provide liquidityresult in an available cash balance in the cash reserve account sufficient to pay approximately one year’s current and expected liabilities and Administrative Expenses of the Trust during any periods in which the Trust does not receive a distribution from BP Alaska. OnTrust. In December 19, 2018, the Trust issued a press release to announce that the Trustee determineddecided to gradually increase the Trustee’s existing cash reserve for the payment of future expensesAdministrative Expenses and liabilities of the Trust, as permitted by the Trust Agreement. The gradual increase in the cash reserve will beginbegan with the distribution payable to Unit holders in April 2019. The Trust did not receive any Royalty Payments attributable to 2020 for the four quarters during 2020 and as a result, the Trust has been unable to make a quarterly deduction to replenish the funds on deposit in the cash reserve account since the January 2020 distribution made for Royalty Payments attributed to the fourth quarter of 2019. In December 2020, the remaining funds on deposit in the cash reserve were insufficient to pay the current Administrative Expenses. On December 28, 2020, the Trust received an indemnity payment from HNS under Section 7.02 of the Trust Agreement in the amount of $537,835, representing the Trust’s current unpaid Administrative Expenses through December 18, 2020. Although HNS agreed to make an indemnity payment to reimburse the Trust for current Administrative Expenses incurred by the Trustee on behalf of the Trust through December 18, 2020, there can be no assurance that HNS will make any further indemnification payments and in such case, the Trustee will continue to review its options under the Trust Agreement and Support Agreement to enforce such indemnity, if necessary, or otherwise obtain funds to pay the Trusts’ Administrative Expenses.

At December 31, 2020, the cash balance of the cash reserve account was $188,579. The Trust anticipates incurring additional Administrative Expenses in excess of the cash balance of the reserve fund. The Trust is exploring all of the options available under the Trust Agreement to address the Trust’s continuing operational shortfall. These steps may include obtaining a loan for the Trust, selling a portion of the Trust assets, or selling all of the Trust assets and taking the necessary steps to terminate the Trust. The Trustee has engaged a firm with expertise in the oil industry to provide financial advisory, investment banking, valuation, and consulting services to assist the Trust in identifying a potential lender or potential purchaser of Trust assets, and to advise the Trust with respect to the timing of its potential termination pursuant to the Trust Agreement. There can be no assurance that the Trust will be able to secure a loan or arrange for the sale of Trust assets, or if it can, that the loan or sale will be on terms that are acceptable to the Trust. See Item 7 in Part II below.

Irrevocability; Amendment of the Trust Agreement

The Trust Agreement and the Trust are irrevocable. No person has the power to terminate, revoke or change the Trust Agreement except as described in the following paragraph and below under “Termination of the Trust.”

The Trust Agreement may be amended without a vote of the Unit holders to cure an ambiguity, to correct or supplement any provision of the Trust Agreement that may be inconsistent with any other provision or to make any other provision with respect to matters arising under the Trust Agreement that does not adversely affect the Unit holders. The Trust Agreement also may be amended with the approval of holders of a majority of the outstanding Units. However, no such amendment may alter the relative rights of Unit holders unless approved by the affirmative vote of holders of 100% of the outstanding Units, nor may any amendment reduce or delay the distributions to the Unit holders, alter the voting rights of Unit holders or the number of Units in the Trust, or make certain other changes, unless approved by the affirmative vote of holders of at least 80% of the outstanding Units and by the Trustee. The Trustee is required to consent to any amendment approved by the requisite vote of Unit holders unless the amendment affects the Trustee’s rights, duties and immunities under the Trust Agreement. No amendment will be effective until the Trustee has received a ruling from the Internal Revenue Service or an opinion of counsel to the effect that such modification will not adversely affect the classification of the Trust as a “grantor trust” for federal income tax purposes or cause the income from the Trust to be treated as unrelated business taxable income for federal income tax purposes.

Termination of the Trust

The Trust will terminate if either (a) holders of at least 60% of the Units outstanding Units vote to terminate the Trust or (b) the net revenues from the Royalty Interest for two successive years are less than $1,000,000 per year (unless the net revenues during thetwo-year period have been materially and adversely affected by certain extraordinary events)a “force majeure” event). As used in the Trust Agreement, “force majeure” means, without limitation: (i) acts of God; strikes, lockouts or other industrial disturbances; acts of public enemies; orders or restraints of any kind of the government of the United States or of the State of Alaska or any of their departments, agencies, political subdivisions or officials, or any civil or military authority; insurrections; civil disturbances; riots; epidemics; sabotage; war, whether or not declared; landslides; lightning; earthquakes; fires; hurricanes; winds; tornados; storms; droughts; floods; arrests; restraint of government and people; explosions; breakage, malfunction or accident to facilities, machinery, transmission pipes or canals; partial or entire failure of utilities; shortages of labor, materials, supplies or transportation; or (ii) any other cause, circumstance or event (other than depletion of the petroleum reservoir in which the Trust has an interest) not reasonably within the control of HNS.

Upon termination of the Trust, BP AlaskaHNS will have an option to purchase the Royalty Interest 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, or (ii) the number of outstanding Units multiplied by (a) the closing price of Units on the day of termination of the Trust on the stock exchange on which the Units are listed, or (b) if the Units are not listed on any stock exchange but are traded in theover-the-counter market, the closing bid price on the day of termination of the Trust as quoted on the NASDAQ Stock Market. The purchase must be for cash unless holders of 60% of the Units outstanding authorize the sale fornon-cash consideration and the Trustee has received a ruling from the Internal Revenue Service or an opinion of counsel to the effect that suchnon-cash sale will not adversely affect the classification of the Trust as a “grantor trust” for federal income tax purposes or cause the income from the Trust to be treated as unrelated business taxable income for federal income tax purposes.

If BP AlaskaHNS does not exercise its option, the Trustee will sell the Trust property 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 property as set forth in the opinion of the investment banking firm, commercial banking firm or other entity mentioned above and on terms and conditions deemed commercially reasonable by that firm.

The Trustee willis obligated to distribute allthe available net proceeds of any such sale to the Unit holders after satisfying all existingestablishing reserves for liabilities of the Trust and establishing adequate reserves for the payment of contingent liabilities.Trust.

Unit holders do not have the right under the Trust Agreement to seek or secure any partition or distribution of the Royalty Interest or any other asset of the Trust or any accounting during the term of the Trust or during any period of liquidation and winding up.

Resignation or Removal of Trustee

The Trustee may resign at any time or be removed with or without cause by vote of the holders of a majority of the outstanding Units at a meeting called and held in accordance with the Trust Agreement. A successor trustee may be appointed by BP AlaskaHNS or, if the Trustee has been removed at a meeting of the Unit holders, the successor trustee may be appointed by the Unit holders at the meeting. Any successor trustee must be a corporation organized, doing business and authorized to exercise trust powers under the laws of the United States, any state thereof or the District of Columbia, or a national banking association domiciled in the United States, in either case having a combined capital, surplus and undivided profits of at least $50,000,000 and subject to supervision or examination by federal or state authorities. Unless the Trust already has a trustee that is a resident of or has a principal office in Delaware, any successor trustee must be a resident of Delaware or have a principal office in Delaware. No resignation or removal of the Trustee will become effective until a successor trustee has accepted appointment.

Voting Rights of Unit Holders

Unit holders possess certain voting rights, but their voting rights are not comparable to those of shareholders of a corporation. For example, there is no requirement for annual meetings of Unit holders or for periodic reelection of the Trustee.

A meeting of the Unit holders may be called at any time to act with respect to any matter as to which the Trust Agreement authorizes the Unit holders to act. Any such meeting may be called by the Trustee in its discretion and will be called by the Trustee (i) as soon as practicable after receipt of a written request by BP AlaskaHNS or a written request that sets forth in reasonable detail the action proposed to be taken at the meeting and is signed by holders of at least 25% of the Units outstanding Units or (ii) when required by applicable laws or regulations or the New York Stock Exchange. The Trustee will give written notice of any meeting stating the time and place of the meeting and the matters to be acted on not more than 60 days nor fewer than 10 days before the meeting to all Unit holders of record on a date not more than 60 days before the meeting at their addresses shown on the records of the Trust. All meetings of Unit holders are required to be held in the Borough of Manhattan, New York City. Unit holders are entitled to cast one vote on all matters coming before a meeting, in person or by proxy, for each Unit held on the record date for the meeting.

For more information regarding the Trust, see a copy of the Trust Agreement which has been filed with the SEC as an Exhibit 4.1 to this report.

THE ROYALTY INTEREST

The Royalty Interest is a property right under Alaska law which burdens production, but there is no other security interest in the reserves or production revenues assigned to it. The royalty payable to the Trust for each calendar quarter is the sum of the amounts obtained by multiplying Royalty Production for each day in the calendar quarter by the Per Barrel Royalty for that day. The payment under the Royalty Interest for any calendar quarter may not be less than zero nor more than the aggregate value of the total production of oil and condensate from BP Alaska’sHNS’s working interest in the Prudhoe Bay Unit for the quarter, net of the State of Alaska royalty and less the value of any applicable payments made to affiliates of BP Alaska.HNS.

Royalty Production

The “Royalty Production” for each day in a calendar quarter is 16.4246% of the lesser of (i) the first 90,000 barrels of the actual average daily net production of crude oil and condensate for the quarter from the Prudhoe Bay (Permo-Triassic) Reservoir and saved and allocated to the oil and gas leases owned by HNS (as successor to BP AlaskaAlaska) in the Prudhoe Bay field as of February 28, 1989 (the “1989“1989 Working Interests”Interests”), or (ii) the actual average daily net production of crude oil and condensate for the quarter from the 1989 Working Interests. The Royalty Production is based on oil produced from the oil rim and condensate produced from the gas cap, but not on gas production or natural gas liquids production. The actual average daily net production of oil and condensate from the 1989 Working Interests for any calendar quarter is the total production of oil and condensate for the quarter, net of the State of Alaska royalty, divided by the number of days in the quarter.

Per Barrel Royalty

The “Per“Per Barrel Royalty”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.

WTI Price

The “WTI Price”“WTI Price” for any trading day is (i) the price (in dollars per barrel) for West Texas intermediate crude oil of standard quality having a specific gravity of 40 API degrees for delivery at Cushing, Oklahoma (“West Texas Intermediate”Intermediate”) quoted for that trading day by whichever of The Wall Street Journal, Reuters, or Platts Oilgram Price Report, in that order, publishes West Texas Intermediate price quotations for the trading day, or (ii) if the price of West Texas Intermediate is not published by one

of those publications, the WTI Price will be the simple average of the daily mean prices (in dollars per barrel) quoted for West Texas Intermediate by one major oil company, one petroleum broker and one

petroleum trading company designated by BP Alaska,HNS, in each case unaffiliated with BPHNS and having substantial U.S. operations, until published price quotations are again available. If prices for West Texas Intermediate are not quoted so as to permit the calculation of the WTI Price, the price of “West“West Texas Intermediate,” for the purposes of calculating the WTI Price will be the price of another light sweet domestic crude oil of standard quality designated by BP AlaskaHNS and approved by the Trustee, with appropriate allowance for transportation costs to the Gulf coast (or another appropriate location) to equilibrate its price to the WTI Price. The WTI Price for any day which is not a trading day is the WTI Price for the preceding trading day.

Chargeable Costs

The “Chargeable Costs”“Chargeable Costs” per barrel of Royalty Production for each calendar year are fixed amounts specified in the Conveyance and do not necessarily represent BP Alaska’sHNS’s actual costs of production. Chargeable Costs per barrel were $16.90 during 2014, $17.00 during 2015, $17.10 during 2016, $17.20 during 2017, and $20.00 during 2018. Chargeable Costs for2018, $23.75 during 2019, and subsequent years are shown in the following table:

$26.50 during 2020. After 2020, Chargeable Costs increase at a uniform rate of $2.75 per barrel per year.

Cost Adjustment Factor

Pursuant to the Overriding Royalty Conveyance,²the “Cost“Cost Adjustment Factor”Factor” for a quarter was initially set as the ratio of the Consumer Price Index³ published for the most recently past February, May, August or November, as the case may be, to 121.1 (thethe Consumer Price Index for January 1989).1989. The Overriding Royalty Conveyance provides, however, that if the average WTI Price for any calendar quarter falls to $18.00 or less,⁴, the Cost Adjustment Factor for that quarter will be the Cost Adjustment Factor for the immediately preceding quarter. If the average WTI Price returns to more than $18.00 for a later quarter, then for each subsequent quarter that the average WTI Price remains above $18.00, adjustments to the Cost Adjustment Factor resume, but with an adjustment to the formula that excludes changes in the Consumer Price Index during the period that adjustments to the Cost Adjustment Factor were suspended.⁵

Production Taxes

“Production Taxes”Taxes” are the sum of any severance taxes, excise taxes (including windfall profit tax, if any), sales taxes, value added taxes or other similar or direct taxes imposed upon the reserves or production, delivery or sale of Royalty Production, computed at defined statutory rates.

On April 14, 2013, Alaska’s legislature passed anoil-tax reform bill amending Alaska’s oil and gas production tax statutes, AS 43.55.10et seq. (the “Production“Production Tax Statutes”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”“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-stepper-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 (as predecessor to HNS) dated January 15, 2014 (the “2014“2014 Letter Agreement”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-stepper-barrel tax credits for the Royalty Production during that quarter. If there is a “minimum tax”-related limitation on the amount of the stair-stepper-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 (as predecessor to HNS) and the Trustee signed a letter agreement (the “2014“2014 Letter Agreement Amendment”Amendment”) amending the 2014 Letter Agreement to provide that if there is a “minimum tax”-related limitation on the amount of the stair-stepper-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.

TheAs a result of the 2014 Letter Agreement Amendment, became effective immediately. Thus, for 2018 any difference between the limitation as preliminarily determined for the first through third quarters of 20182020 and the actual limitation for 2018 will be2020 is reflected in the payment to the Trust for the fourth quarter of 2018,2020, and not in the payment to the Trust for the first quarter of 2019.2021.

Per Barrel Royalty Calculations

The following table shows how the above-described factors interacted during the past five years to produce the average Per Barrel Royalty, if any, paid during the calendar years indicated. Royalty revenues are generally received on the fifteenth day of the month following the end of the calendar quarter in which

the related Royalty Production occurred. Revenues and expenses presented in the statement of cash earnings and distributions presented in Part II, Item 8 below are recorded on a modified cash basis and, as a result, royalty revenues and distributions shown in such statements for any calendar year are attributable to BP Alaska’sHNS’s operations during the twelve-month period ended September 30 of that year. Dollar amounts in the table have been rounded to two decimal places for presentation and do not reflect the precision of the actual calculations.

THE UNITS

Units

Each Unit represents an equal undivided share of beneficial interest in the Trust. The Units do not represent an interest in or an obligation of BP Alaska,HNS, Standard Oil or any of their respective affiliates. Units are evidenced by transferable certificates issued by the Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit. The Trust has no other authorized or outstanding class of securities.

Distributions of Income

BP AlaskaHNS makes quarterly payments to the Trust of the amounts due with respect to the Trust’s Royalty Interest on the fifteenth day following the end of each calendar quarter or, if the fifteenth is not a business day, on the next succeeding business day (the “Quarterly“Quarterly Record Date”Date”). The Trustee pays all expenses of the Trust for each quarter on the Quarterly Record Date to the extent possible, then distributes the excess, if any, of the cash received by the Trust over the Trust’s expenses, net of any additions to or subtractions from the cash reserve established for the payment of estimated liabilities (the “Quarterly Distribution”“QuarterlyDistribution”), to the persons in whose names the Units were registered at the close of business on the Quarterly Record Date.

The Trust Agreement requires the Trustee to pay the Quarterly Distribution to Unit holders on the fifth day after the Trustee’s receipt of the amount paid by BP Alaska.HNS. Cash balances held by the Trustee for distribution to Unit holders are required to be invested in United States government or agency obligations secured by the full faith and credit of the United States (“Government Obligations”Obligations”) or, if Government Obligations that mature on the date of the distribution to Unit holders are not available, in repurchase agreements secured by Government Obligations with banks having capital, surplus and undivided profits of $100,000,000 or more (which may include The Bank of New York Mellon). If time does not permit the Trustee to invest collected funds in Government Obligations or repurchase agreements, the Trustee may invest funds overnight in a time deposit with a bank meeting the foregoing capital requirement (including The Bank of New York Mellon).

Reports to Unit Holders

After the end of each calendar year, the Trustee mailsprovides a report to the persons who held Units of record during the year containing information to enable them to make the calculations necessary for federal and Alaska income tax purposes, including the calculation of any depletion or other deduction which may be available to them for the calendar year. In addition, after the end of each calendar year the Trustee mailsprovides Unit holders an annual report containing a copy of this Form10-K and certain other information required by the Trust Agreement.

Limited Liability of Unit Holders

The Trust Agreement provides that the Unit holders are, to the full extent permitted by Delaware law, entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under Delaware law.

Possible Divestiture of Units

The Trust Agreement imposes no restrictions on nationality or other status of the persons eligible to hold Units. However, it provides that if at any time the Trust or the Trustee is named a party in any judicial or administrative proceeding seeking the cancellation or forfeiture of any property in which the Trust has an interest because of the nationality, or any other status, of any one or more Unit holders, the Trustee may require each holder whose nationality or other status is an issue in the proceeding to dispose of his Units to a party not of the nationality or other status at issue in the proceeding. If any holder fails to dispose of his Units within 30 days after receipt of notice from the Trustee to do so, the Trustee will redeem any Units not so transferred within 90 days after the end of the30-day period specified in the notice for a cash price equal to the fair market value of the Units. Units redeemed by the Trustee will be cancelled.

The Trustee may cause the Trust to borrow any amount required to redeem the Units. If the purchase of Units from an ineligible holder by the Trustee would result in anon-exempt “prohibited transaction” under the Employee Retirement Income Security Act of 1970, or under the Internal Revenue Code of 1986, the Units subject to the Trustee’s right of redemption will be purchased by BP AlaskaHNS or a designee of BP Alaska.HNS.

Issuance of Additional Units

The Trust Agreement provides that BP AlaskaHNS or an affiliate from time to time may assign to the Trust additional royalty interests meeting certain conditions and, upon satisfaction of various other conditions, the Trust may issue up to an additional 18,600,000 Units. HNS (as successor to BP AlaskaAlaska) has not conveyed any additional royalty interests to the Trust, and the Trust has not issued any additional Units.

THE BP SUPPORT AGREEMENT

BP agreed to provide financial support to BP Alaska (as predecessor to HNS) in meeting its payment obligations to the Trust in a Support Agreement dated February 28, 1989, among BP, BP Alaska, Standard Oil and the Trust (the “Support Agreement”“Support Agreement”). Within 30 days after BP receives notice from the Trustee that the royalty payable with respect to the Royalty Interest or any other amount payable by BP AlaskaHNS or Standard Oil has not been paid to the Trustee (including without limitation, the obligation to make payments as indemnification), BP will cause BP AlaskaHNS and Standard Oil to satisfy their respective payment obligations to the Trust and the Trustee under the Trust Agreement and the Conveyance, including contributing to BP AlaskaHNS the funds necessary to make such payments. BP is required to make available to BP AlaskaHNS and Standard Oil such financial support as BP Alaska,HNS, Standard Oil or the Trustee may request in writing. Any Unit holder has the unconditional right to institute suit against BP to enforce BP’s obligations under the Support Agreement.

Neither BP nor BP AlaskaHNS may transfer or assign its rights or obligations under the Support Agreement without the prior written consent of the Trustee, except that BP can arrange for its obligations to be performed by any of its affiliates so long as BP remains responsible for ensuring that its obligations are performed in a timely manner.

BP AlaskaHNS may sell or transfer all or part of its working interest in the Prudhoe Bay Unit, although such a transfer will not relieve BP of its responsibility to ensure that BP Alaska’sHNS’s payment obligations with respect to the Royalty Interest and under the Trust Agreement and the Conveyance are performed.

BP will be released from its obligation under the Support Agreement upon the sale or transfer of all or substantially all of BP Alaska’sHNS’s working interest in the Prudhoe Bay Unit if the transferee agrees in writing to assume and be bound by BP’s obligation under the Support Agreement. The transferee’s agreement to assume BP’s obligations must be reasonably satisfactory to the Trustee and the transferee must be an entity having a rating of its unsecured, unsupported long-term debt of at least A3 from Moody’s Investors Service, Inc., a rating of at leastA- from Standard & Poor’s, or an equivalent rating from at least one nationally-recognized statistical rating organization (after giving effect to the sale or transfer and the assumption of all of BP Alaska’sHNS’s obligations under the Conveyance and all of BP’s obligations under the Support Agreement).

For more information regarding the Support Agreement, see a copy of the Support Agreement which has been filed with the SEC as an Exhibit 4.4 to this report.

THE PRUDHOE BAY UNIT AND FIELD

Prudhoe Bay Unit Operation and Ownership

Since several oil companies besides BP AlaskaHNS hold acreage within the Prudhoe Bay field, as well as several contiguous oil fields, the Prudhoe Bay Unit was established to optimize field development. Other owners of these fields include affiliates of Exxon Mobil Corporation, ConocoPhillips and Chevron Corporation. The Trust’s Royalty Interest pertains only to production from the 1989 Working Interests in the Prudhoe Bay field and does not include production from the other oil fields included in the Prudhoe Bay Unit.

The operations of BP AlaskaHNS and the other working interest owners in the Prudhoe Bay Unit are governed by an agreement dated April 1, 1977 among the State of Alaska and the working interest owners establishing the Prudhoe Bay Unit (the “Prudhoe“Prudhoe Bay Unit Agreement”Agreement”) and an agreement dated April 1, 1977 among the working interest owners governing Prudhoe Bay Unit operations (the “Prudhoe“Prudhoe Bay Unit Operating Agreement”Agreement”).

The Prudhoe Bay Unit Operating Agreement specifies the allocation of production and costs to the working interest owners. It also defines operator responsibilities and voting requirements and is unusual in its establishment of separate participating areas for the gas cap and oil rim. Since July 1, 2000, BP Alaska has beenserved as the sole operator of the Prudhoe Bay Unit.Unit until June 30, 2020, when Hilcorp completed its acquisition of BP Alaska, converted it to a limited liability company, and changed its name to HNS.

The ownership of the Prudhoe Bay Unit by participating area as of December 31, 20182020 is shown in the following table:

If BP AlaskaHNS fails to pay any costs and expenses chargeable to BP AlaskaHNS under the Prudhoe Bay Unit Operating Agreement and the production of oil and condensate is insufficient to pay such costs and expenses, the Royalty Interest is chargeable with a pro rata portion of such costs and expenses and is

subject to the enforcement against it of liens granted to the operators of the Prudhoe Bay Unit. However, in the Conveyance, BP AlaskaHNS agreed to pay all costs and expenses chargeable to it and to ensure that no such costs and expenses will be chargeable against the Royalty Interest. The Trust is not liable for any loss or liability incurred by BP AlaskaHNS or others attributable to BP Alaska’sHNS’s working interest in the Prudhoe Bay Unit or to the oil produced from it, and BP AlaskaHNS has agreed to indemnify the Trust and hold it harmless against any such impositions.

BP AlaskaHNS has the right to amend or terminate the Prudhoe Bay Unit Agreement, the Prudhoe Bay Unit Operating Agreement and any leases or conveyances with respect to the 1989 Working Interests in the exercise of its reasonable and prudent business judgment without liability to the Trust. BP AlaskaHNS also has the right to sell or assign all or any part of the 1989 Working Interests, so long as the sale or assignment is expressly made subject to the Royalty Interest and the terms and provisions of the Conveyance.

The Prudhoe Bay Field

The Prudhoe Bay field is located on the North Slope of Alaska, 250 miles north of the Arctic Circle and 650 miles north of Anchorage. The Prudhoe Bay field extends approximately 12 miles by 27 miles and contains nearly 150,000 gross productive acres. Approximately 45% of the acreage within the field is subject to the Royalty Interest granted to the Trust by the Conveyance. The Prudhoe Bay field, which was discovered in 1968 by BP and others, has been in production since 1977 and is the largest producing oil field in North America. As of December 31, 2018,2020, approximately 12.612.7 billion barrels of oil and condensate had been produced from the Prudhoe Bay field.

Field Geology

The principal hydrocarbon accumulations at Prudhoe Bay are in the Ivishak sandstone of the Sadlerochit Group at a depth of approximately 8,700 feet below sea level. The Ivishak is overlain by four minor reservoirs of varying extent which are designated the Put River, Eileen, Sag River and Shublik (“PESS”PESS”) formations. Underlying the Sadlerochit Group are theoil-bearing Lisburne and Endicott formations. The net production allocated to the Royalty Interest pertains only to the Ivishak and PESS formations, collectively known as the Prudhoe Bay (Permo-Triassic) Reservoir, and does not pertain to the Lisburne and Endicott formations.

The Ivishak sandstone was deposited, commencing some 250 million years ago, during the Permian and Triassic geologic periods. The sediments in the Ivishak are composed of sandstone, conglomerate and shale which were deposited by a massive braided river and delta system that flowed from an ancient mountain system to the north. Oil was trapped in the Ivishak by a combination of structural and stratigraphic trapping mechanisms.

Gross reservoir thickness is 550 feet, with a maximum oil column thickness of 425 feet. The original oil column is bounded on the top by agas-oil contact, originally at 8,575 feet below sea level across the main field, and on the bottom by anoil-water contact at approximately 9,000 feet below sea level. A layer of heavy oil and tar overlays theoil-water contact in the main field and has an average thickness of around 40 feet.

Oil Characteristics

The oil produced from the Prudhoe Bay (Permo-Triassic) Reservoir is a medium grade, low sulfur crude with an average specific gravity of 27 API degrees. The gas cap composition is such that, upon surfacing, a liquid hydrocarbon phase, known as condensate, is formed.

The Royalty Interest is based upon oil produced from the oil rim and condensate produced from the gas cap, but not upon gas production (which is currently uneconomic on a large scale) or natural gas liquids production stripped from gas produced.

Historical Production

Production from the Prudhoe Bay field began on June 19, 1977, with the completion of the Trans-Alaska Pipeline System (“TAPS”TAPS”). As of December 31, 20182020, there were 1048980 active producing oil wells, 3135 gas reinjection wells, 196311 water injection wells and water and miscible gas injection wells in the Prudhoe Bay field. Production wells drilled in the field during the three years ended December 31, 20182020 were: 33 in 2016, 23 in 2017 and 14 in 2018.2018, 25 in 2019, and 8 in 2020. These include new sidetrack completions in existing wells. No exploratory drilling activities were conducted in the field during the three-year period.period ended December 31, 2020. Production from the Prudhoe Bay field reached a peak in 1988 and has declined steadily since then. The average well production rate was about 177 barrels per day in 2014, 170 barrels per day in 2015, 171 barrels per day in 2016, 178 barrels per day in 2017, and 166 barrels per day in 2018.2018, 163 barrels per day in 2019, and 162 barrels per day in 2020.

HNS’s share of the hydrocarbon liquids production from the Prudhoe Bay field includes oil, condensate and natural gas liquids. Using the production allocation procedures from the Prudhoe Bay Unit Operating Agreement, the Prudhoe Bay field’s total production and the net share of oil and condensate (net of State of Alaska royalty) allocated to the 1989 Working Interests have been as follows during the past five years:

Collection and Transportation of Prudhoe Bay Oil

Raw crude oil produced from individual production wells located at well pads is diverted to flowlines (pipelines). The flowlines transport the raw crude oil to one of six separation facilities (three on the western side of the Prudhoe Bay Unit and three on the eastern side) where the water and natural gas mixed with the raw crude are removed. The stabilized crude is then sent from the separation facilities through two34-inch diameter transit lines, one from each half of the Prudhoe Bay Unit, to Pump Station 1, the starting point for TAPS.

At Pump Station 1, Alyeska Pipeline Service Company, the operator of TAPS, meters the oil and pumps it in the48-inch diameter pipeline to Valdez, almost 800 miles (1,288 km) to the south, where it is either loaded onto marine tankers or stored temporarily. It currently takes the oil about 1620 days to make the trip from the Prudhoe Bay Unit to Valdez. TAPS has a mechanical capacity of 1.12.1 million barrels of oil a day. During 2018,2020, TAPS averaged 509 thousand479,554 barrels per day.

Following a partial shutdown of the eastern side of the Prudhoe Bay Unit which lasted from August 7 until September 22, 2006, BP Alaska replaced approximately 16 miles of oil transit lines and has implemented new integrity management and corrosion monitoring practices that supplementsupplemented or replacereplaced the practices that existed in 2006. BP Alaska states that its integrity management practices meet the requirements of 49 CFR 195.452 for pipeline integrity management in high consequence areas.

Reservoir Management

The Prudhoe Bay field is a complex, combination-drive reservoir, with widely varying reservoir properties. Reservoir management involves directing field activities and projects to maximize the economic value of reserves.

Several different oil recovery mechanisms are currently active in the Prudhoe Bay field, including pressure depletion, gravity drainage/gas cap expansion, water flooding and miscible gas flooding. Separate yet integrated reservoir management strategies have been developed for the areas affected by each of these recovery processes.

Reserve Estimates

Proved oil reserves attributable to the 1989 Working Interests at December 31, 20182020, are those quantities of oil which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from 20192021 forward from known reservoirs and under existing economic conditions, operating methods and government regulations. Estimates of proved reserves are inherently imprecise and subjective and are revised over time as additional data becomes available. Such revisions often may be substantial. BP Alaska’sHNS’s reserve estimates and production assumptions and projections are predicated upon a reasonable estimate of the allocation of hydrocarbon liquids between oil and condensate according to the procedures of the Prudhoe Bay Unit Operating Agreement. Oil and condensate are physically produced in a commingled stream of hydrocarbon liquids. The allocation of hydrocarbon liquids between the oil and condensate from the Prudhoe Bay field is a theoretical calculation performed in accordance with procedures specified in the Prudhoe Bay Unit Operating Agreement. Under the terms of an Issues Resolution Agreement entered into by the Prudhoe Bay Unit owners in October 1990 (the “Issuers “IssuersResolution Agreement”Agreement”), the allocation procedures were adjusted to generally allocate condensate in a manner which approximates the anticipated decline in the production of oil until an agreed original condensate reserve of 1,175 million barrels has been allocated to the working interest owners.

By letter dated December 19, 2014, BP Alaska advised the Trustee that the portion of the hydrocarbon liquids produced from the initial participating areas of the Prudhoe Bay Unit being allocated as condensate from the gas cap participating area was found to have reached on June 8, 2014 the agreed original condensate reserve of 1,175 million barrels allocated to the working interest owners. As a result, the portion of hydrocarbon liquids previously allocated as condensate to the gas cap participating area will be allocated to the oil rim participating area. This event has had the effect of changing the calculation of the volume of Royalty Production subject to the Royalty Interest because 50.68% of hydrocarbon

liquids allocated to the oil rim participating area⁶ are counted for the purpose of calculating such volume, but only 13.84% of the hydrocarbon liquids are allocated to the gas cap participating area for such purpose.⁷ The end of the allocation to the gas cap participating area on June 8, 2014 meant that volumes of hydrocarbon liquids subject to the Royalty Interest for the second and third quarters of 2014 were greater than the volumes of Royalty Production initially reported by BP Alaska. The correction to the volumes of Royalty Production and the Royalty payments with respect to the Royalty Interest for such quarters were made in conjunction with the scheduled Royalty payment in January 2015 for the quarter ended December 31, 2014. See Note 6 of Notes to Financial Statements below.

There is no precise method of forecasting the allocation of reserve volumes to the Trust. The Royalty Interest is not a working interest and the Trust is not entitled to receive any specific volume of reserves from the 1989 Working Interests. The reserve volumes attributable to the 1989 Working Interests are estimated using an allocation of reserve volumes based on estimated future production and the average unweighted arithmetic average of the WTI Price on the first day of each month during the year ($39.57 per barrel for the 12-month period prior to December 31, 2020) in accordance with SEC regulations, and assume no future movement in the Consumer Price Index and no changes to the procedure for calculating Production Taxes. The estimated reserve volumes attributable to the Trust will vary if different estimates of production, prices and other factors are used. Even if expected reservoir performance does not change, the estimated reserves, economic life, and future revenues attributable to the Trust may change significantly in the future. This may result from changes in the WTI Price or from changes in other prescribed variables utilized in calculations defined by the Overriding Royalty Conveyance.

The reserves attributable to the 1989 Working Interests constitute only a part of the overall reserves in the Prudhoe Bay Unit. BP AlaskaHNS has estimated that the proved reserves allocated to the Trust as of December 31, 20182020 were 15.772 million0 barrels of oil and condensate, of which 15.638 million0 barrels are proved developed reserves⁸ and 0.134 million0 barrels are proved undeveloped reserves. Proved developed reserves⁹. are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves attributable to the Trust were increaseddecreased by approximately 6.7024.465 million barrels during 20182020 as a result of the increasedecrease in the West Texas Intermediate price, forecast revisions and capital activities including drilling and well treatments. WTI Price.Additional information regarding changes in estimated quantities of proved oil and condensate, proved developed reserves and proved undeveloped reserves is found below in “Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Reserves (Unaudited)” following the Notes to Financial Statements.

In all cases, the volumes are being progressed as a part of an adopted development plan that calls for drilling of wells over a period of time. BP has a historical record of completing comparable projects. There were no contributions to proved undeveloped reserves from extensions or discoveries during 2018.Based2020.

Based on the 2018 twelve-month2020 12-month average WTI Price¹⁰of $65.56$39.57 per barrel (the unweighted arithmetic average of the WTI Price on the first day of each month during the year), other economic parameters

prescribed by the Conveyance, and utilizing procedures specified in Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”ASC”) 932,Extractive Activities – Oil and Gas, BP AlaskaHNS calculated that as of December 31, 20182020, production of oil and condensate from the proved reserves allocated to the 1989 Working Interests will result in undiscounted estimated future cash flowflows to the Trust of $154.662 million,$0, with a net present value of estimated future cash flows at 10% discount of $138.541 million.$0. In the event of changes in HNS’s current assumptions, including price, oil and condensate recoveries may be changed from the current estimates.

The internal controls applicable to the foregoing estimates of the reserves allocated to the Trust are those employed by BP,HNS, which provides the information to the Trustee. BP AlaskaHNS has advised the Trustee that BP’s vice president of segmentits reserves process is managed by its Chief Reservoir Engineer, the petroleum engineertechnical person primarily responsible for overseeing the preparation of the reserves estimate.all of its reserve estimates. He has 30over 20 years of diversified industryreservoir and operations experience, managing the governanceholds a Bachelor of Science in Petroleum Engineering from Texas A&M University and compliancea Master of BP’s reserves estimation since 2005. HeScience in Petroleum Engineering from Stanford University, is a pastLicensed Professional Engineer in the State of Texas, and is a member of the Society of Petroleum Engineers Oil and Gas Reserves Committee, a sitting member of the American Association of Petroleum Geologists Committee on Resource Evaluation and current chair of the bureau of the United Nations Economic Commission for Europe Expert Group on Resource Classification.SPE. The Trust employs Miller and Lents, Ltd., an international oil and gas consulting firm, to conduct an annual review of BP Alaska’sHNS’s estimates of the proved reserves allocated to the Trust, estimated future net revenues to the Trust, and the remaining period of economic production from the Prudhoe Bay field attributable to the Trust. All Miller and Lents, Ltd. staff members assigned to the BP Prudhoe Bay Royalty Trust are licensed professional engineers. Work was supervised by a licensed professional engineer with more than 15 years of experience with the Trust. AcopyAcopy of the February 25, 201926, 2021, report of Miller and Lents, Ltd.isLtd.is filed as Exhibit 99 to this report.

BP Alaska has undertaken a program of field-wide infrastructure renewal, pipeline replacement, and mechanical improvements to wells. As a consequence of these activities and their required downtime, and the natural production declines discussed above under “Historical Production,” BP Alaska’sHNS’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 in 2016, 20172018, 2019 and 2018. BP Alaska2020. HNS anticipates that its average net production of oil and condensate allocated to the Trust from proved reserves will be below 90,000 barrels per day on an annual average basis mostduring future years. The occurrence of major gas sales could accelerate the decline in net production, due to the consequent decline in reservoir pressure. See Item 1A, “RISK FACTORS.”

Based on the 20182020 twelve-month average WTI Price of $65.56$39.57 per barrel, current Production Taxes, and the Chargeable Costs adjusted as prescribed by the Overriding Royalty Conveyance, it is estimated that royalty payments to the Trust will continue through the year 2022, and would be zero in the following year.2021. Therefore, no proved reserves are currently attributed to the BP Prudhoe Bay Royalty Trust after that date. Even if expected reservoir performance does not change, the estimated reserves, economic life and future net revenues attributable to the Trust may change significantly in the future. This may result from sustained periods of change in the WTI Price, the Production Tax or from changes in other prescribed variables utilized in calculations as defined by the Overriding Royalty Conveyance. In order for the Trust to have associated reserves and future net revenues, the twelve-month average WTI Price per barrel must exceed the Production Taxes and Adjusted Chargeable Costs as prescribed by the Overriding Royalty Conveyance in future years. Assuming a WTI price of $39.57 per barrel, which was the SEC-defined 12-month average in 2020, the projected value of the of the Production Taxes and Adjusted Chargeable Costs as prescribed by the Overriding Royalty Conveyance is $59.87 per barrel in 2021 and $65.38 per barrel in 2022 and continues to increase thereafter.

BP AlaskaHNS is under no obligation to make investments in development projects which would add additionalnon-proved resources to proved reserves and cannot make such investments without the concurrence of the Prudhoe Bay Unit working interest owners. The Prudhoe Bay Unit working interest owners regularly assess the technical and economic attractiveness of implementing projects to increase Prudhoe Bay Unit proved reserves. See Item 1A, “RISK FACTORS,” below.

In the event of changes in BP Alaska’s current assumptions, oil and condensate recoveries may be reduced from the current estimates, unless recovery projects other than those included in the current estimates are implemented.

INDUSTRYCONDITIONSINDUSTRY CONDITIONS AND REGULATIONS

The production of oil and gas in Alaska is affected by many state and federal regulations with respect to allowable rates of production, marketing, environmental matters and pricing. Future regulations could change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted.

In general, BP Alaska’sHNS’s oil and gas activities are subject to existing federal, state and local laws and regulations relating to health, safety, environmental quality and pollution control. BP AlaskaHNS believes that the equipment and facilities currently being used in its operations generally comply with the applicable legislation and regulations. During the past few years, numerous environmental laws and regulations have taken effect at the federal, state and local levels. Oil and gas operations are subject to extensive federal and state regulation and to interruption or termination by governmental authorities due to ecological and other considerations and in certain circumstances impose absolute liability upon lessees for the cost of cleaning up pollutants and for pollution damages resulting from their operations. Although BP AlaskaHNS has advised the Trustee that the existence of legislation and regulation has had no material adverse effect on BP Alaska’sHNS’s current method of operations, the effect of future legislation and regulations cannot be predicted.

Since the end of 2006, the corrosion monitoring and mitigation practices for the oil transit lines in the Prudhoe Bay Unit have been monitored and reviewed by the U.S. Department of Transportation.Transportation (“DOT”). The construction, testing, and commissioning of the new replacement oil transit lines have been inspected by DOT inspectors. The replacement lines have been constructed and are operated and maintained in accordance with the requirements of the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act”“PIPES Act”). The applicable requirements of the subsequent regulations of the PIPES Act began to be phasedphased-in in 2012. The PIPES Act was most recently amended in 2012.December 2020. The PIPES Act of 2020 strengthens the Pipeline and Hazardous Materials Safety Administration’s safety authority and includes provisions that advance the safe transportation of energy and other hazardous materials. The Prudhoe Bay Unit is monitoring the status of the new PIPES Act of 2020 in anticipation of new implementing regulations that may be promulgated under the current administration. See “THE PRUDHOE BAY UNIT AND FIELD – Collection and Transportation of Prudhoe Bay Oil” above.

CERTAIN TAX CONSIDERATIONS

The following is a summary of the principal tax consequences to Unit holders resulting from the ownership and disposition of Units. The laws and regulations affecting these matters are complex, and are subject to change by future legislation or regulations or new interpretations by the Internal Revenue Service, state taxing authorities or the courts. In addition, there may be differences of opinion as to the applicability or interpretation of present tax laws and regulations. BP AlaskaHNS and the Trust have not requested any rulings from the Internal Revenue Service with respect to the tax treatment of the Units, and no assurance can be given that the Internal Revenue Service would concur with the statements below.

Unit holders are urged to consult their tax advisors regarding the effects on their specific tax situations of owning and disposing of Units.

Federal Income Tax

Classification of the Trust

The following discussion assumes that the Trust is properly classified as a grantor trust under current law and is not an association taxable as a corporation.

General Features of Grantor Trust Taxation

A grantor trust is not subject to tax, and its beneficiaries (the Unit holders in the case of the Trust) are considered for tax purposes to own the assets of the trust directly. The Trust pays no federal income tax but files an information return reporting all items of income or deduction. If a court were to hold that the Trust is an association taxable as a corporation, the Trust would incur substantial income tax liabilities in addition to its other expenses.

Taxation of Unit Holders

In computing his federal income tax liability, each Unit holder is required to take into account his share of all items of Trust income, gain, loss, deduction, credit and tax preference, based on the Unit holder’s method of accounting. Consequently, it is possible that in any year a Unit holder’s share of the taxable income of the Trust may exceed the cash actually distributed to him in that year. For example, if the Trustee should add to the reserve for the payment of Trust liabilities or repay money borrowed to satisfy debts of the Trust, the money used to replenish the reserve or to repay the loan is income to and must be reported by the Unit holder, even though the money was not distributed to the Unit holder. In 2020 certain indemnity payments were made by HNS to the Trust to reimburse it for Administrative Expenses incurred in accordance with the Trust Agreement because the Trust did not receive any Royalty Payments attributable to the four quarters during 2020, as described in Item 7 in Part II below. For federal income tax purposes, the receipt of the indemnity payments and the expenses paid with those indemnity payments will not be treated as income or deductions of the Trust or of any Unit holder.

The Trust makes quarterly distributions, to the extent available, to the persons who held Units of record on each Quarterly Record Date. The terms of the Trust Agreement seek to assure to the extent practicable that income, expenses and deductions attributable to each distribution are reportable by the Unit holder who receives the distribution.

The Trust allocates income and deductions to Unit holders based on record ownership at Quarterly Record Dates. It is not known whether the Internal Revenue Service will accept the allocation based on this method.

Depletion Deductions

The owner of an economic interest in producing oil and gas properties is entitled to deduct an allowance for the greater of cost depletion or (if otherwise allowable) percentage depletion on each such property. A Unit holder’s deduction for cost depletion in any year is calculated by multiplying the holder’s adjusted tax basis in his Units (generally his cost less prior depletion deductions) by Royalty Production during the year and dividing that product by the sum of Royalty Production during the year and estimated remaining Royalty Production as of the end of the year. The allowance for percentage depletion generally does not apply to interests in proven oil and gas properties that were transferred after December 31, 1974 and prior to October 12, 1990. The Omnibus Budget Reconciliation Act of 1990 repealed this rule for transfers occurring on or after October 12, 1990. Unit holders who acquired their Units on or after that date may be permitted to deduct an allowance for percentage depletion if such deduction would otherwise exceed the allowable deduction for cost depletion. In order to take percentage depletion, a Unit holder must qualify for the “independent producer” exemption contained in section 613A(c) of the Internal Revenue Code of 1986. Percentage depletion is based on the Unit holder’s gross income from the Trust rather than on his adjusted basis in his Units. Any deduction for cost depletion or percentage depletion allowable to a Unit holder reduces his adjusted basis in his Units for purposes of computing subsequent depletion or gain or loss on any subsequent disposition of Units.

Unit holders must maintain records of their adjusted basis in their Units, make adjustments for depletion deductions to such basis, and use the adjusted basis for the computation of gain or loss on the disposition of the Units.

Taxation of Foreign Unit Holders

Generally, a holder of Units who is a nonresident alien individual or which is a foreign corporation (a “Foreign Taxpayer”“Foreign Taxpayer”) is subject to tax on the gross income produced by the Royalty Interest at a rate equal to 30% (or at a lower treaty rate, if applicable). This tax is withheld by the Trustee and remitted directly to the United States Treasury. A Foreign Taxpayer may elect to treat the income from the Royalty Interest as effectively connected with the conduct of a United States trade or business under Internal Revenue Code section 871 or section 882, or pursuant to any similar provisions of applicable treaties. If a Foreign Taxpayer makes this election, it is entitled to claim all deductions with respect to such income, but a United States federal income tax return must be filed to claim such deductions. This election once made is irrevocable unless an applicable treaty provides otherwise or unless the Secretary of the Treasury consents to a revocation.

Section 897 of the Internal Revenue Code and the Treasury Regulations thereunder treat the Trust as if it were a United States real property holding corporation. Foreign holders owning more than five percent of the outstanding Units are subject to United States federal income tax on the gain on the disposition of their Units. Foreign Unit holders owning less than five percent of the outstanding Units are not subject to United States federal income tax on the gain on the disposition of their Units, unless they have elected under Internal Revenue Code section 871 or section 882 to treat the income from the Royalty Interest as effectively connected with the conduct of a United States trade or business.

If a Foreign Taxpayer is a corporation which made an election under Internal Revenue Code section 882(d), the corporation would also be subject to a 30% tax under Internal Revenue Code section 884. This tax is imposed on U.S. branch profits of a foreign corporation that are not reinvested in the U.S. trade or business. This tax is in addition to the tax on effectively connected income. The branch profits tax may be either reduced or eliminated by treaty.

Sale of Units

Generally, a Unit holder will realize gain or loss on the sale or exchange of his Units measured by the difference between the amount realized on the sale or exchange and his adjusted basis for such Units. Gain on the sale of Units by a holder that is not a dealer with respect to such Units will generally be treated as capital gain. However, pursuant to Internal Revenue Code section 1254, certain depletion deductions claimed with respect to the Units must be recaptured as ordinary income upon sale or disposition of such interest.

Backup Withholding

A payor must withhold 24% of any reportable payment if the payee fails to furnish his taxpayer identification number (“TIN”TIN”) to the payor in the required manner or if the Secretary of the Treasury notifies the payor that the TIN furnished by the payee is incorrect. Unit holders will avoid backup withholding by furnishing their correct TINs to the Trustee in the form required by law.

Widely Held Fixed Investment Trusts

The Trustee assumes that some Trust Units are held by a middleman, as such term is broadly defined in the U.S. Treasury Regulations (which includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a widely held fixed investment trust (“WHFIT”WHFIT”) for U.S. Federal income tax purposes. The Bank of New York Mellon Trust Company, N.A. is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. For information contact The Bank of New York Mellon Trust Company, N.A., Global Corporate Trust – Corporate Finance, 601 Travis Street, Floor 16, Houston, TX 77002, telephone number (713)483-6020.

State Income Taxes

Unit holders may be required to report their share of income from the Trust to their state of residence or commercial domicile. However, only corporate Unit holders will need to report their share of income to the State of Alaska. Alaska does not currently impose an income tax on individuals or estates and trusts. All Trust income is Alaska source income to corporate Unit holders and should be reported accordingly.

Foreign Account Tax Compliance Act

Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as “FATCA”“FATCA”), distributions from the Trust to “foreign financial institutions” and certain other“non-financial foreign entities” may be subject to U.S. withholding taxes. Specifically, certain “withholdable payments” (including certain royalties, interest and other gains or income from U.S. sources) made to a foreign financial institution ornon-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution ornon-financial foreign entity complies with certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial institutions andnon-financial foreign entities located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules. Foreign Unit holders are encouraged to consult their own tax advisors regarding the possible implications of these withholding provisions on their investment in Trust Units.

OwnersThe Trust’s operations and financial results are subject to various risk and uncertainties, including those described below, any of which could adversely affect the Trust’s operations, results, financial condition and prospects. In such an event, the market price of the Units are exposed tocould decline, and you may lose all or part of your investment. Additional risks and uncertainties that are particular to their investment.

The Prudhoe Bay field has been in production since 1977. Development of the field is largely completed and proved reserves are being depleted. Production of oil and condensate from the field has been declining during recent years and the decline is expected to continue. As discussed above under the caption “THE PRUDHOE BAY UNIT and FIELD – Reserve Estimates”, Royalty paymentsnot presently known to the Trust or that the Trust currently deems immaterial may also adversely affect the Trust. You should carefully consider the risk described below and the other information in this Annual Report on Form 10-K, including the Trust’s audited financial statements and the related notes thereto, and “The Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.”

Risks Related To Royalty Payments

There were no royalty payments to unit holders for the 2020 fiscal year and there may not be any royalty payments to unit holders in the 2021 fiscal year.

The Trust did not receive any Royalty Payments attributable to the four quarters during 2020 due to, among other things, a significant decline in WTI prices. The determination of Royalty Payments is based in part on the WTI price, and is calculated as an average over the relevant quarter, lessening the effect of price swings through the period. WTI prices fell from around $61 per barrel at the beginning of 2020 to below $14 per barrel on April 22, 2020. During the period from January 2020 to January 2021, WTI prices remained below the price required to exceed the “break even” WTI price (the price at which all taxes and prescribed deductions are equal to the WTI price) in order for the Trust to receive a positive Per Barrel Royalty with respect to a particular day’s production. Additionally, as WTI prices change, so do the taxes and prescribed deductions, potentially increasing or decreasing the “break even” WTI price. While future oil prices cannot be accurately projected, the U.S. Energy Information Administration (“EIA”) forecasts in its Short-Term Energy Outlook (“STEO”), released on March 9, 2021, that WTI prices will average approximately $57.24 per barrel in 2021 and $54.75 in 2022. Should this forecast of WTI prices prevail, the Trust will not receive a positive Per Barrel Royalty with respect to any day’s production during 2021 and Unit holders will not receive Royalty Payments during 2021 or 2022. The projected value of the Production Taxes and Chargeable Costs as prescribed by the Conveyance is $60.72 per barrel in 2021 and $66.46 in 2022, and continues to increase thereafter.

Although the Trust does not expect to receive a positive Per Barrel Royalty for any day’s production during 2021, the Trustee expects to retain in reserve future Royalty Payments, if any, made in fiscal 2021 or subsequent periods for future Administrative Expenses of at least $1,270,000 and potentially more in an amount sufficient to pay Administrative Expenses for at least one year plus anticipated expenses in connection with the termination of the Trust. In order to comply with the Trust Agreement’s termination process and requirements, the Trust is likely to incur significant additional expenditures. Accordingly, even if the Trust receives Royalty Payments during 2021 or 2022, it is not currently anticipated that Unit holders will receive Royalty Payments on outstanding Units during such periods.

The Trust does not have adequate cash to pay its expenses and is exploring options either to obtain financing or to sell Trust assets.

In order to ensure that the Trust had the ability to pay all future Administrative Expenses, the Trust previously established a cash reserve account. The cash reserve account has been funded from periodic deductions from Royalty Payments. These deductions were intended to result in an available cash balance in the cash reserve account sufficient to pay the Administrative Expenses of the Trust for one year. Because the Trust did not receive any Royalty Payments attributable to the four quarters during 2020, the Trust has been unable to make a quarterly deduction to replenish the funds on deposit in the cash reserve account since the January 2020 distribution made for Royalty Payments attributed to the fourth quarter of 2019. In December 2020, the remaining funds on deposit in the cash reserve were insufficient to pay the current Administrative Expenses and the Trustee made a demand for indemnity and reimbursement of

Administrative Expenses upon HNS in accordance with the Trust Agreement in the amount of $537,835, representing the Trust’s current unpaid Administrative Expenses through December 18, 2020. On December 28, 2020, HNS paid the requested funds to the Trustee and the Trustee applied those funds to the Trust’s current unpaid expenses in accordance with the Trust Agreement. Although HNS agreed to make an indemnity payment to reimburse the Trust for current Administrative Expenses incurred by the Trustee on behalf of the Trust through December 18, 2021, there can be no assurance that HNS will make any further indemnification payments and in such case, the Trustee will continue to review its options under the Trust Agreement and Support Agreement to enforce such indemnity, if necessary, or otherwise obtain funds to pay the Trusts’ Administrative Expenses.

At December 31, 2020, the cash balance of the cash reserve account was $188,579. The Trust anticipates incurring additional Administrative Expenses in excess of the cash balance of the reserve fund. The Trust is exploring all options available under the Trust Agreement to address the Trust’s continuing operational shortfall. These steps may include obtaining a loan for the Trust, selling a portion of the Trust assets, or selling all of the Trust assets and taking the necessary steps to terminate the Trust. Such financings or sales in accordance with the Trust Agreement do not require the vote of Unitholders, provided certain conditions are satisfied. The Trustee has engaged a firm with expertise in the oil industry to provide financial advisory, investment banking, valuation, and consulting services to assist the Trust in identifying a potential lender or potential purchaser of Trust assets, and to advise the Trust with respect to the timing of its potential termination pursuant to the Trust Agreement. There can be no assurance that the Trust will be able to secure a loan or arrange for the sale of all or a portion of Trust assets, or if it can, that the loan or sale of assets will be on terms that are acceptable to the Trust. In addition, in the absence of more favorable third-party financing, an affiliate of HNS may elect to offer loan financing to the Trust in lieu of making indemnity payments. Such loan financings or asset sales may limit funds available from future Royalty Payments or the future amount of Royalty Payments payable on Trust assets. The uncertainty surrounding receipt of future royalties necessary for the Trust to avoid termination, coupled with the Trust’s current liquidity position, raises substantial doubt regarding the Trust’s ability to continue as a going concern.

Net revenues for 2020 to the Trust were less than $1,000,000 and estimated net revenues to the Trust for 2021 are expected to be less than $1,000,000, which will result in the termination of the Trust.

The Trust will terminate if either (a) holders of at least 60% of the outstanding Units vote to terminate the Trust or (b) the net revenues from the Royalty Interest for two successive years are less than $1,000,000 per year (unless the net revenues during the two-year period have been materially and adversely affected by an event constituting a “force majeure” as defined in the Trust Agreement). Upon termination of the Trust, HNS will have an option to purchase the Royalty Interest at a price equal to the greater of (i) the fair market value of the Trust property, or (ii) the market value of the outstanding Units based on calculations using a 2018 WTI Pricethe closing price of $65.56 per barrel, among other prescribed variables, are projected to cease after 2022.

Production estimates included in this report are basedUnits on economic conditions and production forecasts asthe New York Stock Exchange on the day of termination of the endTrust. If HNS does not exercise its option, the Trustee will sell the Trust property on terms and conditions approved by the vote of 2018,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 alsothe sale is made at a price at least equal to the fair market value of the Trust property and upon conditions deemed commercially reasonable. After the payment of all Administrative Expenses and after establishing reserves for liabilities of the Trust, the Trustee is obligated to distribute the available net proceeds of any such sale to the Unit holders.

Pursuant to the terms of the Trust Agreement, if net revenues during such two-year period have been materially and adversely impacted by an event constituting “force majeure”, the termination of the Trust may be delayed. As used in the Trust Agreement, “force majeure” means, without limitation: (i) acts of God; strikes, lockouts or other industrial disturbances; acts of public enemies; orders or restraints of any kind of the government of the United States or of the State of Alaska or any of their departments, agencies, political subdivisions or officials, or any civil or military authority; insurrections; civil disturbances; riots; epidemics; sabotage; war, whether or not declared; landslides; lightning; earthquakes; fires; hurricanes; winds; tornados; storms; droughts; floods; arrests; restraint of government and people; explosions; breakage, malfunction or accident to facilities, machinery, transmission pipes or canals; partial or entire failure of utilities; shortages of labor, materials, supplies or transportation; or (ii) any other cause, circumstance or event (other than depletion of the petroleum reservoir in which the Trust has an interest) not reasonably within the control of HNS. If delayed, the Trust would incur additional liabilities. Also, the process required by the Trust Agreement to effect a sale of assets and to terminate the Trust will cause the Trust to incur additional liabilities, including without limitation, additional Administrative Expenses. Any such additional liabilities would reduce proceeds available for distribution to Unit holders from the sale of Trust assets made in connection with a Trust termination. The Trustee has engaged a firm with expertise in the oil industry to provide financial advisory, investment banking, valuation, and consulting services to assist the Trust in identifying a potential lender or potential purchaser of Trust assets, and to advise the Trust with respect to the timing of its potential termination pursuant to the Trust Agreement. There can be no assurance as to the timing of an eventual termination of the Trust.

Royalty payments by HNS to the Trust are unpredictable because such payments depend on various assumptions, projections and estimatesCushing, Oklahoma WTI spot prices, which, like crude oil prices in general, are continually revised and updated by BP Alaska. These revisions could result in material changessubject to the projected declines in production. It is possible that economic production from the reserves allocated to the 1989 Working Interests could decline more quickly and end sooner than is currently projected.

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Royalty payments by BP Alaska to the Trust are unpredictable, because they depend on Cushing, Oklahoma WTI spot prices, which, like crude oil prices in general, are subject to volatility, and on the volume of production from the 1989 Working Interests, which may vary from quarter to quarter in the future.volatility.

WTI prices, like prices in the global crude oil market generally, are subject to periodic fluctuations and significant volatility. This was dramatically demonstrated byThe impact of the precipitous declineCOVID-19 pandemic had a significant impact on the oil industry in WTI Prices from more than $76 per barrel on October 3, 2018 to under $43 dollars per barrel on December 25, 2018. While some analysts had predicted that crude2020, forcing U.S. oil prices would exceed $100 per barrel in 2018to go negative for the first time since 2014, WTIon record. Worldwide demand for oil fell rapidly as governments closed businesses and restricted travel due to the COVID-19 pandemic and oil producers were faced with a glut of crude oil, which made it difficult for them to find space to store the oversupply. In April, the oversupply of oil led to an unprecedented collapse in oil prices, finishedforcing the year down by 25% at $45.41 percontract futures price for West Texas Intermediate (WTI) to plummet from $18 a barrel andto around $(37) a barrel. Brent crude the international benchmark, finished the yearoil prices also tumbled, closing at $50.57 per$9.12 a barrel on April 21, 2020 down by almost 20%. This was the first annual decline in WTI and Brent crude prices since 2015. Atfrom $70 a barrel at the beginning of the fourth quarter of 2018, crudeyear. Several other factors contributed to 2020’s volatility. An oil prices were at four-year highs. The sudden drop in oil prices in the fourth quarter of 2018 ended a twoprice war between Russia and a half year recovery after global oil prices had declined more than 70% from June 2014 through the middle of February 2016. While oil prices are generally expected to rise in 2019, the economic and geopolitical factors that led to the fall in oil prices in the fourth quarter of 2018 may have a negative impact on the recovery of oil prices in 2019.

The reasons for the sudden decline in oil prices in the fourth quarter of 2018 were not generally anticipated earlier in the year. President Trump’s decision in early May to withdraw the U.S. from the Iran nuclear agreement resulted in a greater than 6% rise in oil prices, as the withdrawal was expected to lead to the renewal of U.S. economic sanctions on Iran and adversely affecting Iran’s oil industry. With global oil supplies declining at that time and an increased probability of further supply reductions due to limitations on Iran’s oil exports, Saudi Arabia and Russia agreederupted in September 2018March 2020 when the two nations failed to increase production to help contain rising oil prices in order to support demand.

However, by October 2018, certain events – such as the sharp drop in the U.S. stock market due to disappointing third quarter earnings reports (particularly by the large “FANG” technology stocks (Facebook, Amazon, Netflix and Google parent Alphabet)), the continuing U.S.-China trade dispute and the prospect of continued increases in interest rates by the U.S. Federal Reserve Board – contributed to concerns ofreach a global economic slowdown, helping to depress crude oil prices. The strengthening of the U.S. dollar also weighedconsensus on oil prices by decreasing demand in emerging markets for crude oil, which is sold in dollars. Also, larger than expected increases in U.S. crude inventories in October helped alleviate concernsproduction levels. By the summer of a global oil supply shortage that had helped to boost oil prices earlier in the year. The increases in inventories suggested that global demand for oil would grow more slowly than anticipated earlier in the year.

While global demand for crude started to decrease, the rise in oil prices earlier in the year had led U.S. shale producers to increase production. According to the U.S. Energy Information Administration (“EIA”), a record high in U.S. daily production of 10.9 million barrels was reached in the first week of June. The EIA also estimated in its January 2019 Short-Term Energy Outlook (“STEO”) that total U.S. crude oil production averaged 10.9 million barrels per day in 2018, an increase of 1.6 million barrels per day compared to production in 2017. As a result, the U.S. became the world’s leading producer of crude oil in 2018.

The combination of increasing supply and decreasing demand resulted in the largest drop in crude oil prices in October 2018 since July 2016. Moreover, when the U.S. sanctions on Iran were restored on November 5, 2018, eight major importers of Iranian crude oil were unexpectedly granted exemptions, contributing further to the downward pressure on crude oil prices by decreasing the amount of crude that had been expected to be withdrawn from the global market.

In response to this situation, OPEC and certainnon-OPEC producers led by Russia agreed in December 2018 to reduce their output by 1.2 million barrels per day in an effort to decrease the expanding crude surplus in the market. Subsequently, after the 2018 fourth quarter decline,2020, oil prices began to recover atrebound as nations emerged from lockdown and OPEC agreed to significant cuts in crude oil production. By year’s end, optimism over the possible rollout of multiple COVID-19 vaccines buoyed the market; in November, Brent crude oil spot prices increased to an average of $43 a barrel and WTI crude oil spot prices increased to an average of $42.30. From the beginning of the first quarter of 2019.2021 through March 8, 2021, the WTI crude oil spot price fluctuated between a high of $66.09 per barrel on March 5, 2021, and a low of $47.62 per barrel on January 4, 2021. The WTI crude oil spot price on March 8, 2021 was $65.05 per barrel.

With respectCOVID-19 has caused substantial disruption in the oil industry and has had a negative impact on WTI prices and the receipt of Royalty Payments by the Trust.

In December 2019, a novel strain of coronavirus, SARS-CoV-2 (severe acute respiratory syndrome coronavirus 2), surfaced in Wuhan, China, and has since spread to 2019, EIA forecasts that total global oil production will exceed consumption forother countries, including the first halfUnited States. In March 2020, the World Health Organization characterized the disease caused by the virus—COVID-19—as a pandemic. The pandemic resulted in governments around the world implementing stringent measures to help control the spread of the year.virus, including quarantines, “shelter in place” and “stay at home” orders, travel restrictions, business curtailments and other measures. While governments and central banks in several parts of the world have enacted fiscal and monetary stimulus measures to counteract the impact of COVID-19, the pandemic has resulted in significant economic contraction. The EIA forecasts that oil supplies will riseindustry, in particular, was substantially disrupted, both domestically and internationally, by about 1.4 million barrels per daythe COVID-19 pandemic, which has caused significant changes in 2019, primarily as a result of increasing U.S. production. U.S. output is expected to average 12.4 million barrels per day, an increase from the 2018 record production of 10.9 million barrels per day. Although the EIA forecasts that demand will grow by approximately 1.5 million barrels per day, such growth is not expected to offset the anticipated increases inenergy fuel supply until the third quarter of 2019.and demand. As a result, oilWTI prices could continue to be volatile in the coming year. Partially offsetting this increase in U.S. output will be the decrease in production agreed to by OPEC and the coalition of producers led by Russia. Also in December 2018, the Alberta government decided to impose production cuts of 325,000 barrelsfell from around $63 per day until the excess storage supply in Canada is reduced. More recently, the sanctions imposed by the U.S. on Petróleos de Venezuela SA (“PDVSA”), Venezuela’s state-owned oil and natural gas company, in January of this year are expected to remove additional amounts of crude from the market. The sanctions prohibit U.S. firms from importing Venezuelan crude oil that was not already in transitbarrel at the timebeginning of 2020 to below $8.91 per barrel on April 21, 2020. Although WTI prices have recovered significantly since then, they have remained below the price required to reach the “break even” WTI price (the price at which all Production Taxes and prescribed deductions for Chargeable Costs are equal to the WTI price) in order for the Trust to receive a positive Per Barrel Royalty with respect to a particular day’s production.

Risks Related to WTI Price

The amount and value of reserves attributable to the Trust, the estimated life of the sanctions.

In its February 2019 STEO, EIA forecast that Brent spot prices will average $61 per barrel in 2019Trust, estimates of future net revenues and $62 per barrel in 2020. According toestimates of the February 2019 STEO, WTI crude oil prices will average about $8 per barrel lower than Brent prices during the first quarterpresent value of 2019 but gradually fall to $4 per barrel in the fourth quarter of 2019. This $4 per barrel discount of WTI to Brent is expected to continue through 2020.    EIA anticipates that increases in crude oil production in the United States will be offset in part by decreased production elsewhere, particularly in OPEC. In its January 2019 STEO, the EIA forecast that global consumption will increase by 1.5 million barrels per day in 2019, with growth largely coming from China, the United States, and India. EIA expects that the substantial price declines in the fourth quarter of 2018 together with OPEC production cuts will help keep global crude supply and demand in balance. This balance is expected to keep prices at around current levels in the near term. However, EIA’s supply and demand forecast for 2019 is subject to significant uncertainty. Actual results or changes in market expectations regarding supply and demand could cause significant price fluctuations in 2019.

The forecast that the spread between WTI and Brent prices will decrease by the fourth quarter of 2019 assumes that certain limitationsfuture net revenues fluctuate based on the capacity to transport crude oil fromWTI Price, among other factors. WTI Prices may be below the Cushing, Oklahoma storage hub to the Gulf Coast will be alleviated after the middle of the year. At that“break-even” point EIA expects that new capacity to carry crude oil from West Texas to the Gulf Coast will go into operation and will reduce current distribution bottlenecks throughout Texas and Oklahoma. In prior periods, Cushing has occasionally become oversupplied due to new oil flows from Canada and the United States. Historically, this market had been reliant on high-cost rail and trucks to ship both crude oil stored at Cushing and production from Canada and the Bakken shale formation to the Gulf Coast. These constraints on transportation of crude oil out of the U.S. Midwest market, together with the great increase in production in North America and the decades-long U.S. ban on crude oil exports, had helped to weigh down WTI spot prices for several years and kept the price of WTI crude oil at a historic discount to globally traded waterborne crudes such as Brent. Prior to that period, WTI, which is generally a sweeter and lighter crude oil than Brent, had been more likely to trade at a premium to Brent.daily royalty calculations.

After diverging in 2011 to a high of around $30 per barrel, with Brent the more expensive oil, the spread between WTI and Brent gradually decreased as these transportation problems appeared to be largely resolved. For example, the direction of the Seaway crude oil pipeline was reversed in 2012 and pump station additions and modifications were subsequently made. In 2014 the “Seaway Twin” pipeline running parallel to the reversed Seaway pipeline was opened. Also in 2014, the Cushing MarketLink phase of the Keystone pipeline went into operation. This portion of the Keystone pipeline starts at Cushing, where American-produced oil is added to the pipeline’s Canadian oil. The pipeline then runs south to terminals in Nederland, Texas near refineries located in the Port Arthur, Texas area. The Houston Lateral pipeline also began operating in 2017. This is a47-mile pipeline transporting crude oil from the MarketLink pipeline in Liberty County, Texas, to refineries and terminals in the Houston area. Also, in December 2017, the Plains All American and Valero Diamond Pipeline went into operation. This pipeline, with a capacity of 200,000 barrel per day, connects Cushing to Valero’s refinery in Memphis, Tennessee.

Despite this increase in pipeline capacity out of Cushing, the tremendous growth in U.S. production, could result in additional transportation bottlenecks at Cushing, helping to widen the gap between WTI and Brent prices. In November 2018, Plains All American Pipeline LP announced that the expanded Sunrise Pipeline oil system from the Permian basin to Cushing was placed into service. While this development is expected to provide relief from transportation constraints in the Permian basin, it will help increase the flow of crude oil to Cushing. The expanded Sunrise Pipeline currently transports approximately 300,000 to 350,000 barrels per day and can ultimately transport approximately 500,000 barrels per day from Midland to Colorado City and Wichita Falls, Texas, and provides connections to Cushing. Also, the Saddlehorn pipeline, completed in 2016, which runs from Carr, Colorado to Platteville, Colorado, where it links up with the Grand Mesa Oil Pipeline, is currently capable of transporting 190,000 barrels per day to storage facilities in Cushing.    The Matador pipeline, which will run 38 miles from Adams County, Colorado to the Saddlehorn terminal in Platteville Colorado for ultimate delivery to Cushing, is also currently under development and is expected to be in service by late 2019. The Matador pipeline will have an initial capacity of 220,000 barrels per day.

It was expected that even more crude oil would flow into Cushing following the approval by the Trump administration in January 2017 of a permit allowing TransCanada to build the Keystone XL pipeline and the approval by the Nebraska Public Service Commission of a new route for the pipeline in November 2017. Nebraska was the only state that had not yet approved the route of the pipeline. However, on November 8, 2018, a U.S. federal district court judge in Montana ordered a temporary halt to construction of the Keystone XL pipeline and ordered the U.S. Department of State to conduct a supplemental environmental impact statement. This could lead to additional delays to the project. However, TransCanada forecasts that, if the project is ultimately completed, Keystone XL would eventually carry up to 830,000 barrels of oil per day. This could significantly increase the total amount of crude oil flowing into Cushing via the Keystone pipeline system. The first part of that system, which runs through North and South Dakota, Nebraska and Missouri, went into operation in 2010 and connects Hardisty, Alberta to the Wood River Refinery in Roxana, Illinois, and the Patoka Oil Terminal Hub north of Patoka, Illinois. The pipeline has a nominal capacity of 435,000 barrels per day. The second part of the Keystone system is a 291 mile-long pipeline connection running from Steele City, Nebraska south to Cushing, Oklahoma. This Keystone-Cushing pipeline, which opened in 2011, transports 100,000 barrels of crude oil per day to Cushing. The Keystone XL pipeline would enter the U.S. through Montana, where American-produced oil would be added to the pipeline, and would then connect with the existing Keystone pipeline at Steele City, Nebraska. This would increase the amount of oil in the Keystone system flowing east to Illinois refineries and south to Cushing.

While insufficient outgoing pipeline capacity capable of transporting the crude oil entering Cushing could, as in prior years, depress WTI prices, pipeline capacity out of Cushing continues to increase, with new projects expected to go into operation in the near future. Magellan Midstream Partners, L.P. and

Navigator Energy Services have proposed a pipeline project known as Voyager. This pipeline would be nearly 500 miles long and would link the companies’ terminals in Cushing and East Houston. Once the Voyager reaches Houston, the pipeline is expected to be able to link to refineries in the region as well as to crude oil export facilities. The Voyager, which would have an initial capacity of at least 250,000 barrels per day, would also link with the Saddlehorn pipeline and the Glass Mountain pipeline, which services Midcontinent basins, as well as with other connections within Cushing. Also, in August 2018, Tallgrass Energy, LP (“Tallgrass”) announced that it plans to develop a new crude oil pipeline, known as the Seahorse Pipeline, from Cushing to the refining complex located in St. James, Louisiana. The approximately 700 mile long pipeline is expected to transport up to 800,000 barrels of crude oil per day from Cushing to the Louisiana Gulf Coast. The pipeline is expected to start operations in the third quarter of 2021. The other potential project to help relieve Cushing bottlenecks is the Capline reversal project. Capline currently transports crude oil from St. James, Louisiana, to Patoka, Illinois. Although Capline does not connect to Cushing, it could divert crude oil that would otherwise flow through Cushing.

The spread between the Brent price and the price of U.S. domestic production has also been affected by the lifting of the U.S. ban on crude oil exports which was introduced in the 1970’s. This ban was lifted in December 2015 and provided an outlet for U.S. oil to help prevent inventories from building up, which could cause prices to decrease. The removal of the ban could also contribute to wider use of WTI as a global benchmark. For the week through November 30, 2018, the U.S. exported more oil than it imported for the first time in 75 years. The EIA forecasts in the February 2019 STEO that by the fourth quarter of 2020, the U.S. will be a net exporter of crude oil and petroleum products by approximately 1.1 million barrels per day.

If OPEC andnon-OPEC nations continue to adhere to the production cuts agreed to in December 2018, U.S. producers may have an opportunity to gain access to additional international markets. This possibility of losing market share to the U.S. could jeopardize compliance with the agreed-upon production levels by OPEC and the other producing countries. However, in a recent development, it was reported in early February 2019 that OPEC was seeking to enter into a formal relationship with the group of 10 oil producing nations led by Russia.

As discussed above under “THE ROYALTY INTEREST” in Item 1, revenuesRevenues to the Trust are calculated daily by BP AlaskaHNS using the WTI price, production tax, and other variables as prescribed by the Conveyance applicable on that specific day. On January 1, 2019 theThe “break-even” WTI price (at which all taxesProduction Taxes and prescribed deductions for Chargeable Costs are equal to the WTI price) was $47.69.¹¹is projected to be approximately $60.72 per barrel in 2021 and $66.46 per barrel in 2022, and will continue to increase thereafter. The quarterly royalty paymentRoyalty Payment by BP AlaskaHNS to the Trust is the sum of the individual revenues calculated each day during the quarter. In the event that one or more daily calculations results in a negative amount, the total of such daily negative amounts during that calendar quarter would be subtracted from total daily positive amounts during such quarter to determine the royalty payment for such quarter, provided, that in no event will any quarterly royalty payment be less than zero.

The estimated future net revenues and present value of estimated future net revenues reported hereinin this Annual Report are calculated based on a single average WTI price, that being the average of 12 WTI values, each value representing the WTI price in effect on the first calendar day of the month for the 12 months prior to January 1, 2019.2021. As a result, any single calculation of a calendar day will not reflect the value of the dividend paid to the Trust for any quarter, nor will it reflect the estimated future value of the Trust or the estimation of how long royalty payments to the Trust will continue.

Based on the 20182020 twelve-month average WTI Price of $65.56$39.57 per barrel, current Production Taxes, and the Chargeable Costs adjusted as prescribed by the Overriding Royalty Conveyance, it is estimated that royalty payments to the Trust will continue through the year 2022, and would be zero in the following year.2021. Therefore, no proved reserves are currently attributed to the BP Prudhoe Bay Royalty Trust after that date. Even if expected reservoir performance does not change, the estimated reserves, economic life and future net revenues attributable to the Trust may change significantly in the future as a result of sustained periods of change in the WTI Price, the Production Tax or from changes in other prescribed variables utilized in calculations as defined by the Overriding Royalty Conveyance. Such changes could result in the termination of royalty payments prior to 2022.

While energy price forecasts are highly uncertain, the EIA forecastsforecast in its STEO dated March 9, 2021, that Brent crude oil spot prices will average approximately $61$60.67 per barrel in 20192021 and WTI spot prices will average $55$57.24 per barrel in 2019. 2021 and $54.75 in 2022. EIA’s forecast of declining crude oil prices and a more balanced oil market reflect global oil supply surpassing oil demand during the second half of 2021. Although EIA expects inventories to fall by 1.2 million barrels per day in the first half of 2021, increases in global oil supply will contribute to inventories rising by almost 0.4 million barrels per day in the second half of 2021 and a mostly balanced market in 2022. However, the forecast depends heavily on future production decisions by OPEC+, the responsiveness of U.S. tight oil production to higher oil prices, and the pace of oil demand growth, among other factors.

As discussed under “THE PRUDHOE BAY UNIT AND FIELD – Reserve Estimates”, the amount and value of reserves attributable to the Trust and the estimated life of the Trust fluctuate based on changes to certain prescribed factors, including the WTI price. WTI prices at the level forecast by EIA should,will not, subject to the effect of the other prescribed variables, result in positive royalty payments to the Trust in 2021, if such prices actually constitute the 20192021 twelve-month average WTI Price (that is, the unweighted arithmetic average of the WTI price on the first day of each month during the year). If the actual 2019 twelve-month average WTI Price is lower than forecast, this could

Crude oil prices can be highly volatile as a result subject to the effectof many factors that are outside of the other prescribed variables, in substantial decreases in the value and the estimated lifecontrol of the Trust as calculated for such periods compared to the 2018 calculations set forth under “THE PRUDHOE BAY UNIT AND FIELD – Reserve Estimates”.Trust.

However, futureFuture domestic and international events and conditions may produce wide swings in crude oil prices over relatively short periods of time. Recent moves in crude oil prices have been affected by many factors. These include the effects of COVID-19 on the global economy, changes in demand due to variations in economic activity, increased efficiency, increased demand for other types of fuel, strong production growth, new supplies from tight and shale resources, whether OPEC and other oil producing nations have been willing to intervene, and the success of such intervention, to stabilize oversupplied crude oil markets by cutting production or to take other measures in order to preserve or expand market share, shifts in inventory management strategies by international oil companies, conservation measures by consumers,

increasing effects of the oil futures market and other unpredictable political, geopolitical, psychological and economic factors, such as developments with respect toincreased tensions between the U.S. and Iran, political unrest in Iran and developments with respect to the Iran nuclear deal, the continuing collapse of Venezuela’s oil industry, tensions between North Korea and South Korea and the U.S., the strength or weakness of the U.S. dollar (the currency in which crude oil is quoted, with crude oil prices, like prices of other commodities priced in dollars, generally moving inversely to the value of the dollar), how the policies of the U.S. administration may influence oil production and markets, expectations for global economic growth, developments relating to the U.S.-China trade dispute, events relating to the departure of the United Kingdom from the European Union (“Brexit”Brexit”), political turmoil in North AfricaLibya threatening that country’s oil production and the Middle East andexports, ongoing tensions in other regions of the world and turmoil and volatility in global stock markets.

For additional information, see the history ofhistorical WTI Prices since 1986 published byare available from the U.S. Energy Information AdministrationAdministration.

The amount and value of reserves attributable to the Trust, the estimated life of the Trust, estimates of future net revenues and estimates of the present value of future net revenues fluctuate based on the WTI Price, among other factors. WTI Prices have been, and are expected to continue to be, below the “break-even” point for daily royalty calculations.

As discussed above under “THE ROYALTY INTEREST” in Item 1, revenues to the Trust are calculated daily by HNS using the WTI price, production tax, and other variables as prescribed by the Conveyance applicable on that specific day. The fixed Chargeable Cost increases specified in the Conveyance have impacted and will continue to impact “break-even” prices. The quarterly royalty payment by HNS to the Trust is the sum of the individual revenues calculated each day during the quarter. In the event that one or more daily calculations results in a negative amount, the total of such daily negative amounts during that calendar quarter would be subtracted from total daily positive amounts during such quarter to determine the royalty payment for such quarter, provided, that in no event will any quarterly royalty payment be less than zero.

The estimated future net revenues and present value of estimated future net revenues reported herein are calculated based on a single average WTI price, that being the average of 12 WTI values, each value representing the WTI price in effect on the first calendar day of the month for the 12 months prior to January 1, 2021. As a result, any single calculation of a calendar day will not reflect the value of the dividend paid to the Trust for any quarter, nor will it reflect the estimated future value of the Trust or the estimation of how long royalty payments to the Trust will continue.

Based on the 2020 twelve-month average WTI Price of $39.57 per barrel, current Production Taxes, and the Chargeable Costs adjusted as prescribed by the Overriding Royalty Conveyance, it is estimated that royalty payments to the Trust would be zero in 2021. Therefore, no proved reserves are currently attributed to the BP Prudhoe Bay Royalty Trust after that date. Even if expected reservoir performance does not change, the estimated reserves, economic life and future net revenues attributable to the Trust may change significantly in the future as a result of sustained periods of change in the WTI Price, the Production Tax or from changes in other prescribed variables utilized in calculations as defined by the Overriding Royalty Conveyance.

While energy price forecasts are highly uncertain, EIA, forecasts that WTI spot prices will average $57.24 per barrel in 2021. As discussed under “THE PRUDHOE BAY UNIT AND FIELD – Reserve Estimates”, the amount and value of reserves attributable to the Trust and the estimated life of the Trust fluctuate based on changes to certain prescribed factors, including the WTI price. Since the “break-even” WTI price (at which all Production Taxes and prescribed deductions for Chargeable Costs are equal to the

WTI price) is projected to be approximately $60.72 per barrel in 2021, WTI prices athttp://tonto.eia.doe.gov the level forecasted by EIA will not, subject to the effect of the other prescribed variables, result in positive royalty payments to the Trust in 2021, if such prices actually constitute the 2021 twelve-month average WTI Price (that is, the unweighted arithmetic average of the WTI price on the first day of each month during the year).

The impact that cash distributions with respectthe sale of BP’s Alaska assets to their UnitsHilcorp Alaska, LLC may vary widely from quarterhave on the 1989 Working Interests is difficult to quarter.determine.

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 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.

In August 2006, BP Alaska shut down the eastern side of the Prudhoe Bay Unit following the discovery of unexpectedly severe corrosion and a small spill from the oil transit line on that side of the Unit. Earlier, in March of 2006, BP had to temporarily shut down and commence the replacement of a three-mile segment of transit line on the western side of the Prudhoe Bay Unit following discovery of a large oil spill.

BP Alaska completely replaced approximately 16 miles of transit lines on the eastern and western sides of the Prudhoe Bay Unit and has implemented federally-required corrosion monitoring practices. However, the discovery of additional defects in Prudhoe Bay Unit oil flowlines and transit lines, and damage to or failures of separation facilities or other critical equipment, could result in future shutdowns of oil production from all or portions of the Prudhoe Bay Unit and have an adverse effect on future royalty payments.

The Trans-Alaska Pipeline System connects the North Slope oil fields to the southern port of Valdez, almost 800 miles away. It is the only way that oil can be transported from the North Slope to market. The pipeline system crosses three mountain ranges, many rivers and streams and thaw-sensitive permafrost. It is susceptible along its length to damage from earthquakes, forest fires and other natural disasters. The pipeline system also is vulnerable to failures of pipeline segments and pumping equipment, accidental damage and deliberate attacks. Recently, the pipeline has become susceptible to damage resulting from declining flows of oil from the North Slope. Slower flows cause the temperature of the oil in the pipeline to cool faster, increasing the rate of deposit of wax, which coats pipe walls, hides corrosion and clogs sensors on smart pigs sent through the pipeline to detect it. Even lower flow rates projected in the future may lead to internal damage caused by ice formation within the pipe and external damage from frost heaves under buried segments. Major upgrades to the pipeline may be required to counteract the effects of cooler oil temperature. If the pipeline or its pumping stations should suffer major damage from natural orman-made causes, production from the Prudhoe Bay Unit could be shut in until the pipeline system can be repaired and restarted. In both 2011 and 2018, TAPS was shut down temporarily – in one case because of a leak and in the other because of an earthquake. Royalty payments to the Trust could be halted or reduced by a material amount as a result of interruption to production from the Prudhoe Bay Unit.

In January 2011, TAPS was shut down over two periods of several days each as a result of the discovery of a leak of crude oil in the basement of a booster pump building at Pump Station No. 1. See “THE PRUDHOE BAY UNIT AND FIELD — Collection and Transportation of Prudhoe Bay Oil” in Item 1 for additional information.

As noted above, without more crude oil to be transported by TAPS, slower flows and freezing temperatures could eventually force the closure of the pipeline, making it impossible to transport oil from the North Slope to market. In 2018, after two consecutive years of increase,2019, the pipeline’s average throughput decreased by approximately 18,000 barrels per day in 2018 compared to 2017.2018. This amounted to a 3.43.7 percent decrease. The 20182019 throughput was the pipeline’s second lowest annual daily average after 2015. Beforeaverage. 2019 was the 2016 increase, the last increasesecond consecutive year of decreased throughput following two consecutive years of increases in pipeline throughput was in 2002, when the pipeline carried over one million barrels per day. The 2016 and 2017 increases have been attributed to a combination of factors, such as better than expected performance from newer oil fields west of Prudhoe Bay, such as ConocoPhillips’CD-5 development on the North Slope in the Colville River Unit (part of the Alpine Field and the first commercial oil development on Alaska Native lands within the boundaries of the National Petroleum Reserve-Alaska (“NPRA”) as discussed below) and the ability of oil companies to produce oil from mature fields like Prudhoe Bay more efficiently.2017. Nevertheless, throughput for the last three years has averaged only 518,169509,001 barrels per day. The pipeline was designed to carry much higher volumes of oil. In 2011, a study by Alyeska raised questions as to whether TAPS could continue in operation below a throughput level of approximately 300,000 barrels per day. A 2018 update of the 2011 low flow study details stepsoil and while Alyeska is taking or plans to take – such as adding heat to maintain crude oil temperature within operating parameters—steps to mitigate the problems associated with slower oil flow through the pipeline. Thepipeline, the EIA which(which has forecast continued declining production from the North Slope,Slope) has also noted that considerable investment could be required to keep TAPS operational if throughput goes below 350,000 barrels per day.

However,Alaska’s Department of Revenue has also forecast that Alaska North Slope oil production will decline to an average of 492,000 barrels per day in potentially significant developments for Alaska and TAPS,the fiscal year that ends June 30, 2020, which is down from the 494,900 barrels per day produced in fiscal 2019. Production is expected to decline further through 2024 before subsequently increasing to 494,500 barrels per day by 2029, as recent discoveries in the North Slope begin production. New North Slope discoveries in 2016, 2017 and 2018 could increase crude oil production byadd as much as 40 percent during the next eight years, according to data and information services provider IHS Markit. Among other discoveries, Caelus Energy LLC, a small energy exploration company, announced in October 2016 that it had discovered oil in Smith Bay on Alaska’s northern coast. The company reported that the field could hold as much as 6 billion barrels of oil and that it expects to be able to recover between 1.8 to 2.4 billion barrels. However, due to the complexity and expense of the project and the length of the regulatory process, oil from the discovery is not expected to flow to TAPS until 2022. In March of 2017, a partnership between Spanish oil company Repsol and its U.S. partner, Armstrong Energy, announced a significant oil discovery in the Nanushuk formation located across the central and western portion of the North Slope. The partnership predicted that production could begin as soon as 2021 and could produce as much as 120,000 barrels of oil per day. According to the partnership, the discovery, located in a well known as Horseshoe, is 20 miles south of where Repsol-Armstrong had already found oil in 2014 and 2015 in a project known as the Pikka Unit. The Pikka project is already in early development and it is anticipated that first production will begin in 2021, with a possible production of nearly 120,000 barrels of oil per day. Also in January 2017, ConocoPhillips announced a new oil discovery, known as Willow, located in the Greater Mooses Tooth Unit on ConocoPhillips’ leases in the northeastern portion of NPRA. According to ConocoPhillips, Willow could produce up to 100,000 barrels of oil per day. Production at Willow is expected to begin in 2023. In addition, production at ConocoPhillip’sCD-5 development reached 37,000 barrels of oil per day in 2018, more than originally projected. ConocoPhillips also announced in October 2018 that it had begun production at its Greater Mooses Tooth 1 field (“GMT1”), also located in the NPRA. The field is projected to eventually produce up to 38,000 barrels per day. In October 2018, the Bureau of Land Management and the U.S. Army Corps of Engineers issued a Joint Record of Decision approving ConocoPhillips’ Greater Mooses Tooth 2 project (“GMT2”). GMT2 is located about 8 miles west of GMT1 in the NPRA and is expected to produce 35,000 to 40,000360,000 barrels per day during peakof oil production. The Horseshoe, Willow, Smith Bay and GMT discoveries are all located in the Nanushuk formation or the related Torok formation. As a result of these discoveries, it has been projected that over the next five years, ConocoPhillips will be adding 100,000 barrels a day to TAPS.

Another potential source of crude oil in Alaska lies in the 19 million acres of the Arctic National Wildlife Refuge (“ANWR”ANWR”). It is estimated that a1.5-million-acre part of the coastal plain of ANWR known as the “1002 area” contains 11.8 billion barrels of potentially recoverable crude oil. A40-year-old ban on energy development in the ANWR was removed when the Tax Cuts and Jobs Act (the “TCJA”“TCJA”) was enacted in December 2017. The TCJA includes a provision that permits oil exploration and drilling in the 1002 area. In addition,An administration plan to hold an oil and gas lease sale in the ANWR before the end of 2019 did not take place because of certain procedural delays. The Trump administration also announced in January 2018 that it would allow new offshore oil and gas drilling in nearly all United States coastal waters, including the Arctic Ocean.

Production from However, in March 2019, a U.S. District Court judge for the 1989 Working Interests may be interrupted or discontinued by BP Alaska.

BPDistrict of Alaska has no obligation to continue production fromruled that the 1989 Working Interests or to maintain production at any levelexecutive order that removed the ban on oil and may interrupt or discontinue production at any time. The Trust does not havegas drilling in the right to take over operationArctic Ocean and parts of the 1989 Working Interests or shareNorth Atlantic coast was unlawful. In addition, President Biden signed an executive order placing a temporary moratorium on oil and gas activity in any operating decisions by BP Alaska concerning the Prudhoe Bay Unit.ANWR on January 20, 2021, one day after the Trump administration had issued nine oil and gas leases in the refuge’s coastal plain. The operationorder places a temporary moratorium on all activities of the Prudhoe Bay Unit is subject to normal operating hazards incidentFederal Government relating to the productionimplementation of the Coastal Plain Oil and transportationGas Leasing Program, as established by the Record of oil in Alaska. In the event of damage to the infrastructure, facilities and equipmentDecision signed August 17, 2020, in the Prudhoe Bay field which is covered by insurance, BP Alaska has no obligation to use insurance proceeds to repair such damageANWR, pending a review of the program and, may elect to retain such proceedsas appropriate and close damaged areas to production.consistent with applicable law, a new, comprehensive analysis of the potential environmental impacts of the oil and gas program.

Construction of a gas pipeline from the North Slope of Alaska could accelerate the decline in Royalty Production from the Prudhoe Bay field.

The construction of a natural gas pipeline to bring natural gas from the North Slope could make it economical to extract natural gas from the Prudhoe Bay field and transport it to market. Currently, natural gas released by pumping oil is reinjected into the ground, which helps to maintain reservoir pressure and facilitates extraction of oil from the field. Extraction of natural gas from the Prudhoe Bay field would lower reservoir pressure, although carbon dioxide stripped out of the gas could be reinjected and other methods could be employed to mitigate the reduction. The lowering of the reservoir pressure could accelerate the decline in production from the 1989 Working Interests and the time at which royalty payments to the Trust would cease. Since the Trust is not entitled to any royalty payments with respect to natural gas production from the 1989 Working Interests, the Unit holders would not realize any offsetting benefit from natural gas production from the Prudhoe Bay field.

It has long been considered that without a pipeline, extraction of natural gas from the Prudhoe Bay field on a large scale would not be economical. In October 2012, ExxonMobil, ConocoPhillips, BP and Calgary-based TransCanada Corporation (“TransCanada”) notified the Alaska Governor that they had agreed on a plan to combine what were once two competing natural gas pipeline projects destined for the continental U.S. into one project focused on export markets. This project contemplated building an800-mile natural gas pipeline from the North Slope to a port on the southern coast of Alaska from which liquifiedliquefied natural gas (“LNG”) would be exported to Asia. It was contemplated that the project would also include natural gas processing facilities and anatural-gas export terminal.facilities.

In January 2014, it was announced that the state of Alaska would pursue becoming an equity partner in the Alaska natural gas pipeline project and that ExxonMobil, BP, ConocoPhillips, TransCanada, Alaska Gasline Development Corporation (“AGDC”), and Alaska’s commissioners of natural resources and revenue had signed a heads of agreement (“HOA”) for the Alaska LNG Project. This established the commercial framework for the development of the natural gas pipeline from the North Slope to the south-central Alaska coast. The Nikiski area of the Kenai Peninsula was selected as the leading site for the LNG plant. In November 2015, AGDC purchased TransCanada’s 25% interest in the project.

In August 2016, ExxonMobil, BP and ConocoPhilips indicated that they did not currently wish to make further investments in the Alaska LNG project. This decision followed a report, commissioned by ExxonMobil, BP and AGDC, by an energy consultancy firm stating the project’s competitiveness “ranks poorly” under current market conditions. At the end of 2016, it was announced that AGDC had concluded agreements with ExxonMobil, BP and ConocoPhillips to take over the leadership position in the Alaska LNG project. The Alaska LNG project received construction authorization from federal authorities in May 2020, according to publicly-available information.

In November 2017, Alaska state officials announced that AGDC, which is currently the sole owner ofUnlike the Alaska LNG project, had signed a joint development agreement with Sinopec, onewhich contemplates gas from the North Slope being liquefied 800 miles away on the south coast of the world’s largest oil and gas companies, China Investment Corp., the world’s third-largest sovereign wealth fund, and the state-owned commercial bank, Bank of China, to pursue the project.    In January 2019, Alaska, and three Chinese companies agreedinspired by Russia’s Yamal LNG, a new company, Qilak LNG, would forego transporting gas via hundreds of miles of pipeline and proposes, instead, to extend negotiations to conclude definitive agreements for the Alaskaship LNG project until June 30, 2019. In June 2017, it was announced that AGDC had signed an agreement with the Korea Gas Corp. to establish a cooperative framework for the development of Alaska’s natural gas infrastructure.

The Alaska LNG project, which AGDC has stated may cost approximately $43 billion, is currently in the federal regulatory phase. AGDC expects a final environmental reviewfrom production capacity to be completed byconstructed on the Federal Energy Regulatory Commission (FERC) in December 2019 and a record of decision in March 2020. Construction of the project is currently expectedNorth Slope directly to Asian markets on ice-breaking tankers from Point Thomson. A feasibility study was scheduled to begin in 2020 with a goalfinal investment decision (FID) possible in 2021 or 2022. It is anticipated that shipments of transporting natural gas by 2024.    In May 2018, AGDC announced that BP Alaska and AGDC had agreed onLNG could start in the primary terms of a gas sales agreement to supply natural gas to the Alaska LNG project. In September 2018, AGDC also announced that it had agreed to terms and conditions for gas sales with ExxonMobil. Negotiations between ConocoPhillips and AGDC are ongoing.mid-2020s.

The effect of any changes to the Alaska Production Tax Statutes on Per Barrel Royalty and Royalty Production from the Prudhoe Bay field is unpredictable.

As noted (see “THE ROYALTY INTEREST – Production Taxes” in Item 1 above), Alaska’s Production Tax Statutes affect the calculation of the Per Barrel Royalty. Among other changes to the Production Tax Statutes, the 2013 amendments added a stair-stepper-barrel tax credit for oil production, provided that a producer’s tax liability may not be reduced below the “minimum tax”. Since going into effect on January 1, 2014, the 2013 amendments had the effect of reducing Production Taxes imposed on Royalty Production. Moreover, as a result of the low oil price environment that began inmid-2014, Royalty Production has been subject to the minimum tax under the Production Tax Statutes since the first quarter of 2015. The reduction in Production Taxes has in part offset the reduction in royalty payments that resulted from declining WTI prices.

Any changes to the Production Tax Statutes in the future may also impact the amount of Production Taxes and, in turn, the amount of royalty payments. Whether or when any such changes may occur and the effect any such changes may have on the Per Barrel Royalty is unpredictable.

The Production Tax Statutes can also have an impact on Royalty Production from the Prudhoe Bay field. For example, the 2007 amendments to the Production Tax Statutes (see “THE ROYALTY INTEREST – Production Taxes” in Item 1 above) may have accelerated the decline in production of oil and condensate from the Prudhoe Bay field to the extent that it caused BP AlaskaHNS and the other owners of working interests in the Prudhoe Bay Unit to reduce or defer investment in oil production infrastructure renewal, well development and implementation of new technology due to uncompetitive returns on investment in Alaska. The 2007 amendments, in addition to increasing the basic oil production tax rate and the progressivity factor, also eliminated or reduced many deductions and credits permitted under the 2006

amendments to the Production Tax Statutes. Due in part to the 2007 amendments, BP Alaska’s

HNS’s spending on production adding activity, adjusted for inflation, was flat to declining from 2008 through 2012. As noted under “THE ROYALTY INTEREST – Production Taxes” in Item 1 above, the 2013 amendments to the Production Tax Statutes were intended to encourage oil production and investment in Alaska’s oil industry by eliminating the monthly “progressivity” tax rate implemented by 2006 and 2007 amendments and adding a stair-stepper-barrel tax credit for oil production. Due to the low oil price environment that has prevailed for much of the time since the 2013 amendments went into effect, and since the Prudhoe Bay field is a mature field, the impact of the 2013 amendments in terms of encouraging oil production and investment with respect to the Prudhoe Bay field is uncertain.

Risks Related to the Units

The market price for the Trust units may not reflect the value of the assets held by the Trust.

The public trading price for the Trust units has historically been tied to the recent and expected levels of cash distributions on the Trust units. However, it has been suggestedno cash distribution were made for the 2020 fiscal year and none are expected for the 2021 fiscal year. The amounts available for distributions by the Trust vary in response to numerous factors outside the control of the Trust or HNS, including prevailing WTI Prices. The market price of the Trust units is not necessarily indicative of the value that the 2013 amendmentsTrust would realize if the assets were sold to a third party buyer. In addition, the Production Tax Statutes providedmarket price is not necessarily reflective of the impetusfact that, since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a Unit holder over the life of these depleting assets will equal or exceed the purchase price paid by the Unit holder.

Trust Unit holders have limited voting rights and have limited ability to enforce the Trust’s rights against HNS or any other operator of the underlying assets and limited rights and limited ability to assert any claims against the Trustee.

The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the seriesTrustee.

The Trust Agreement and related trust law permit the Trustee and the Trust to sue HNS or any other operator of recent Alaska oil discoveries discussed above.the underlying properties to compel them to fulfill the terms of the Conveyance and to enforce the obligations of HNS (as successor to BP Alaska) under the Support Agreement. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, the Trust Agreement limits and conditions the rights of the Unit holders to assert any claims against the Trustee. These rights are limited and are set forth in Article VII of the Trust Agreement. Unit holders may enforce certain obligations of HNS (as successor to BP Alaska) under the Support Agreement. Unit holders may be limited in their right or ability to sue HNS or any other operator of the underlying properties. In addition, the rights of ultimate beneficial holders of Units may be limited by the Trust Agreement, which confers rights upon Unit “Holders,” which term includes only those holders as show by the records of the Trustee pursuant to Article III of the Trust Agreement.

The interests of BP AlaskaHNS and the Trust with respect to the Prudhoe Bay Unit could at times be different. The Per Barrel Royalty that BP AlaskaHNS pays to the Trust is based on the WTI Price, Chargeable Costs and Production Taxes, all of which are amounts contractually defined in the Conveyance. The WTI Price does not necessarily correspond to the actual price realized by BP AlaskaHNS for crude oil produced from the 1989 Working Interests, and Chargeable Costs and Production Taxes may not bear any relation to BP Alaska’sHNS’s actual costs of production and tax expenses. The actual per barrel profit realized by BP AlaskaHNS on the Royalty Production may differ materially from the Per Barrel Royalty that it is required to pay to the Trust. It is possible under certain circumstances that the relationship between BP Alaska’sHNS’s actual per barrel revenues and costs could be such that BP Alaskacontinued operations may be uneconomic, and, to the extent permitted under the Conveyance and applicable law, HNS might determine to interrupt or discontinue production in whole or in part from the 1989 Working Interests even though a Per Barrel Royalty might otherwise be payable to the Trust under the Conveyance.

The Trust has not received any written comments from the staff of the Securities and Exchange Commission regarding its periodic or current reports under the Securities Exchange Act of 1934 (the “Exchange Act”) that remain unresolved.

Reference is made to Item 1 for the information required by this item.

None

Not applicable.

PART II

The Units are listed and traded on the New York Stock Exchange under the symbol BPT. The following table shows the high and low sales prices per Unit on the New York Stock Exchange and the cash distributions paid per Unit, for each calendar quarter in the two years ended December 31, 2018.

Liquidity and Capital Resources

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 revenue attributable to the Royalty Interest that it receives from time to time. See the discussion under “THE ROYALTY INTEREST” in Item 1 for a description of the calculation of the Per Barrel Royalty, and the discussion under “THE PRUDHOE BAY UNIT AND FIELD – Reserve Estimates” in Item 1 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 Item 1.

SinceIn July 1999, the Trustee has maintainedestablished a $1,000,000 cash reserve to provide liquidity to the Trust during any future periods in which the Trust does not receive a distribution. As noted above under “THE TRUST – Sales of Royalty Interest; Borrowings and Reserves”, on December 19, 2018,distribution from HNS. The Trustee draws funds from the cash reserve account during any quarter in which the quarterly distribution received by the Trust issued a press release to announce thatdoes not exceed the Trustee had determined to gradually increase the Trustee’s existing cash reserve for the payment of futureliabilities and expenses and liabilities of the Trust, as permitted byand replenishes the Trust

Agreement. Commencing with the distribution to Unit holders payable in April, 2019, the Trustee intends to withhold the greater of $33,750 or 0.17% of the funds otherwise available for distribution each quarter to gradually increase existing cash reserves by a total of approximately $270,000.reserve from future quarterly distributions, if any. The Trustee may increase or decrease the targeted amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the Unit holders. The Trustee anticipates that it will keep this cash reserve program in place, to the extent that it receives a distribution from HNS, until termination of the Trust. In December 2018, the Trust announced that the Trustee had determined to gradually increase the Trustee’s existing cash reserve for the payment of future expenses and liabilities of the Trust, as permitted by the Trust Agreement. Commencing with the distribution to Unit holders payable in April, 2019, the Trustee began withholding the greater of $33,750 or 0.17% of the funds otherwise available for distribution each quarter to gradually increase existing cash reserves.

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.

The Trustee will draw funds from the cash reserve account during any quarter in which the quarterly distribution received by the Trust does not exceed the liabilities and expenses of the Trust, and will replenish the reserve from future quarterly distributions, if any. The Trustee anticipates that it will keep this cash reserve program in place until termination of the Trust.

Amounts 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. Interest income received

A novel strain of coronavirus, SARS-CoV-2 (severe acute respiratory syndrome coronavirus 2), surfaced in late 2019 and has since 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 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 fromreceived no Royalty Payment for the investmentquarters ended March 31, June 30, and September 30, 2020 and, as discussed in Note 8 to the financial statements, did not receive a Royalty Payment in January 2021 for the quarter ended December 31, 2020 given oil prices were below the “break-even” WTI price of $54.34 during such periods. The 2020 12-month average WTI Price was $39.57 per barrel.

Because the Trust did not receive any Royalty Payments attributable to the four quarters during 2020, the Trust has been unable to make a quarterly deduction to replenish the funds on deposit in the cash reserve account since the January 2020 distribution made for Royalty Payments attributed to the fourth quarter of 2019. In December 2020, the remaining funds on deposit in the cash reserve were insufficient to pay the current Administrative Expenses 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 current unpaid expenses through December 18, 2020. On December 28, 2020, HNS paid the requested funds to the Trustee and the Trustee applied those funds to the Trust’s current unpaid Administrative Expenses in accordance with the Trust Agreement. Although HNS agreed to make an indemnity payment to reimburse the Trust for current Administrative Expenses incurred by the Trustee on behalf of the Trust through December 18, 2020, there can be no assurance that HNS will make any further indemnification payments and in such case, the Trustee will continue to review its options under the Trust Agreement and Support Agreement to enforce such indemnity, if necessary, or otherwise obtain funds to pay the Trusts’ Administrative Expenses.

At December 31, 2020, the cash balance of the cash reserve account was $188,579. The Trust anticipates incurring additional Administrative Expenses in excess of the cash balance of the reserve fundfund. The Trust is addedexploring the options available under the Trust Agreement to address the Trust’s continuing operational shortfall. These steps may include obtaining a loan for the Trust, selling a portion of the Trust assets, or selling all of the Trust assets and taking the necessary steps to terminate the Trust. The Trustee has engaged a firm with expertise in the oil industry to provide financial advisory, investment banking, valuation, and consulting services to assist the Trust in identifying a potential lender or potential purchaser of Trust assets, and to advise the Trust with respect to the distributions received from BP Alaska and paidtiming of its potential termination pursuant to the Trust Agreement. There can be no assurance that the Trust will be able to secure a loan or arrange for the sale of Trust assets, or if it can that the loan or sale will be on terms that are acceptable to the Trust.

Although the Trust did not receive Royalty Payments attributable to any quarter in 2020, in part due to the decline in WTI prices, the increase in Chargeable Costs and the payment of Production Taxes, coupled with decreased Royalty Production from the Prudhoe Bay Field, significantly reduce the likelihood of any material Royalty Payments to Unit holders in the first or second quarter of 2021, notwithstanding the current upward trend in the WTI Price.

The Trustee expects to retain in reserve future Royalty Payments, if any, made in fiscal 2021 or subsequent periods for future Administrative Expenses of at least $1,270,000 and potentially more in an amount sufficient to pay Trust fees and expenses for at least one year plus anticipated expenses in connection with the termination of the Trust. In order to comply with the Trust Agreement’s termination process and requirements, the Trust is likely to incur significant additional expenditures. Accordingly, even if the Trust receives Royalty Payments during 2021 or 2022, it is not currently anticipated that Unit holders will receive Royalty Payments on each Quarterly Record Date.outstanding Units during such periods.

If the Trust does not receive any additional Royalty Payments in 2021 or thereafter, or obtain alternative funding, the Trust’s ability to meet its obligations would be adversely affected, which raises substantial doubt about its ability to continue as a going concern. As noted above, as a general matter, the Trust is expected to terminate at such time the net revenues from the Royalty Interest for two successive years are less than $1,000,000 per year.

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 as it affects OPEC and other producing countries. The effect of changing 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 to Unit holders in each calendar year ending December 31 are attributable to BP Alaska’sHNS’s operations during the twelve-month period ended on the preceding September 30.

When BP Alaska’sHNS’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, it is likely that the Trust’s revenues in future periods also will be affected by increases and decreases in production from the 1989 Working Interests. BP Alaska’sHNS’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 2016, 20172018, 2019 and 2018.2020. The Trustee has been advised that BP AlaskaHNS 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.

BP Alaska

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 BP AlaskaHNS of actual Royalty Production data may result in revisions of prior Royalty Production estimates. Revisions

by BP AlaskaHNS of its Royalty Production calculations may result in quarterly royalty payments by BP AlaskaHNS 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. See Note 87 of Notes to Financial Statements in Item 8. Because the annual statement of cash earnings and distributions of the Trust is prepared on a modified cash basis, royalty revenues for the calendar year do not include the amounts of underpayments or overpayments affecting payments received during the fourth quarter of the year.

During the years 2017 and 2018 and the period of 2019, up to the date of this report, WTI Prices have beenwere above the level necessary for the Trust to receive a Per Barrel Royalty. However, during, 2020 WTI Prices were below the level necessary for the Trust to receive a Per Barrel Royalty. Whether the Trust will be entitled to future distributions during the remainder of 20192021 will depend on, among other things, WTI Prices prevailing during the remainder of the year.

As discussed above in Item 1A “RISK FACTORS”, it is possible that global oil prices could remain at current or lower levels for a significant period. As also discussed above in Item 1A “RISK FACTORS”, on January 1, 2019,2021, the “break-even” WTI price (the price at which all taxes and prescribed deductions are equal to the WTI price) for the Trust to receive a positive Per Barrel Royalty with respect to a particular day’s production was $47.69.$60.72. From the beginning of the first quarter of 20192021 through February 20, 2019,March 8, 2021, the WTI crude oil spot price fluctuated between a high of $57.11$66.09 per barrel on February 20, 2019March 5, 2021, and a low of $46.31$47.62 per barrel on January 2, 2019.4, 2021. The WTI crude oil spot price on February 21, 2019March 8, 2021 was $56.84$65.05 per barrel. The quarterly royalty payment by BP AlaskaHNS 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.However,Trust.However, if a low oil price environment should occur for a protracted period, quarterly royalty payments could decline significantly, and could in factare likely to be insignificant or be zero.

2018 compared to 2017

As explained in Note 23 of Notes to Financial Statements below, the financial statements of the Trust are prepared on a modified cash basis and differ from financial statements prepared in accordance with generally accepted accounting principles in that (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 and (b) Trust expenses are recorded on an accrual basis. As a consequence, Trust royalty revenues for the fiscal year are based on Royalty Production during the twelve months ended September 30 of the fiscal year.

2020 Compared to 2019

2019 Compared to 2018