UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year ended December 31, 2006

OR

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

Registrant’s telephone number, including area code: (212) 815-6908

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

Title of Each Class		Name of Each Exchange on Which Registered
UNITS OF BENEFICIAL INTEREST		NEW YORK STOCK EXCHANGE

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 þ No o

     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 o No þ

     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 þ No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-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 Form 10-K or any amendment to this Form 10-K. þ

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

     Large Accelerated filer þ       Accelerated filer o       Non-accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act Yes o No þ

     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 30, 2006 (the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $1,709,860,000.

     As of February 28, 2007, 21,400,000 Units of Beneficial Interest were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

TABLE OF CONTENTS

PART I			1
ITEM 1. BUSINESS			1
INTRODUCTION			1
THE TRUST			2
THE ROYALTY INTEREST			6
THE UNITS			11
THE BP SUPPORT AGREEMENT			12
THE PRUDHOE BAY UNIT AND FIELD			13
INDEPENDENT OIL AND GAS CONSULTANTS’ REPORT			19
INDUSTRY CONDITIONS AND REGULATIONS			24
CERTAIN TAX CONSIDERATIONS			24
ITEM 2. PROPERTIES			26
ITEM 1A. RISK FACTORS			27
ITEM 1B. UNRESOLVED STAFF COMMENTS			29
ITEM 3. LEGAL PROCEEDINGS			29
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			30
PART II			30
ITEM 5. MARKET FOR REGISTRANT’S UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS			30
ITEM 6. SELECTED FINANCIAL DATA			31
ITEM 7. TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			31
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			34
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			46
ITEM 9A. CONTROLS AND PROCEDURES			46
ITEM 9B. OTHER INFORMATION			48
PART III			48
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			48

ITEM 11. EXECUTIVE COMPENSATION			49
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS			49
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE			50
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES			50
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES			50
SIGNATURES			52

PART I

     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”) 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 percent of the lesser of (i) the first 90,000 barrels ^* of the average actual daily net production of crude oil and condensate per quarter from the working interest of BP Alaska as of February 28, 1989 in the Prudhoe Bay oil field located on the North Slope in Alaska or (ii) the 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 Alaska and are known collectively as the “Prudhoe Bay Unit.” The Royalty Interest was conveyed to the Trust by an Overriding Royalty Conveyance dated February 27, 1989 from BP Alaska 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 as the “Conveyance.”

     The Royalty Interest is a non-operational 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’s working interest in the Prudhoe Bay field. BP Alaska 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.

Employees

     The Trust has no employees. All administrative functions of the Trust are performed by the Trustee.

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. The Bank of New York (Delaware) has been appointed co-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 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 pay all expenses, 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 are the Trustee’s fees and routine administrative expenses, including accounting, legal and other professional fees.

     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 be indemnified out of the assets of the Trust for any liability or loss incurred by it in the performance of its duties unless the loss results from its negligence, bad faith or fraud or from expenses incurred in carrying out its duties that exceed the compensation and reimbursement to which it is entitled under the Trust Agreement.

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 70 percent of the Units outstanding if the sale is to be effected on or before December 31, 2010, or holders of 60 percent of the Units outstanding if the sale is to be effected after 2010. 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, the sale only needs to be approved by the vote of holders of a majority of the Units. Any sale of Trust properties 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 establishing reserves for 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:

     The Trustee may borrow from a lender not affiliated with the Trustee if cash on hand is not sufficient to pay current liabilities and the Trustee has determined that it is not practical to pay such liabilities out of funds anticipated to be available in subsequent quarters and that, without such borrowing, the Trust property is subject to the risk of loss or diminution in value. To secure payment of its borrowings on behalf of the Trust, the Trustee is authorized to encumber the Trust’s assets and to carve out and convey production payments. The borrowing must be on terms which (in the opinion of an investment banking firm or commercial banking firm selected by the Trustee) are commercially reasonable when compared to other available alternatives. No distributions to Unit holders may be made until the borrowings by the Trust have been repaid in full.

     If the Trustee is unable to borrow to pay Trust liabilities, the Trustee may sell Trust assets if it determines that the failure to pay the liabilities at a later date will be contrary to the best interest of the Unit holders and that it is not practicable to submit the sale to a vote of the Unit holders. The sale must be made for cash at a price which (in the opinion of an investment banking firm or commercial banking firm selected by the Trustee) is at least equal to the fair market value of the interest sold and is made on commercially reasonable terms when compared to other available alternatives.

     The Trustee has the right to establish a cash reserve for the payment of material liabilities of the Trust which may become due if it determines that it is not practical to pay such liabilities out of funds anticipated to be available in subsequent quarters and that, in the absence of a

reserve, the Trust property is subject to the risk of loss or diminution in value or the Trustee is subject to the risk of personal liability for such liabilities.

     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.

     In 1999, the Trustee established a $1,000,000 cash reserve to provide liquidity to the Trust during any periods in which the Trust does not receive a distribution from BP Alaska. 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 percent 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 percent 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: (i) on or before December 31, 2010 if holders of at least 70 percent of the outstanding Units vote to terminate the Trust, or (ii) after December 31, 2010 if either (a) holders of at least 60 percent of the outstanding Units vote to terminate the Trust or (b) the net revenues from the Royalty Interest for two successive years commencing after 2010 are less than $1,000,000 per year (unless the net revenues during the two-year period have been materially and adversely affected by certain extraordinary events).

     Upon termination of the Trust, BP Alaska 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 the over-the-counter market, the closing bid price on the day of termination of the Trust as quoted on the NASDAQ National Market System. The purchase must be for cash unless holders of 70 percent of the Units outstanding (60 percent if the decision to terminate the Trust is made after December 31, 2010) authorize the sale for non-cash consideration and the Trustee has received a ruling from the Internal Revenue Service or an opinion of counsel to the effect that such non-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 Alaska does not exercise its option, the Trustee will sell the Trust property on terms and conditions approved by the vote of holders of 70 percent of the outstanding Units (60 percent if the sale is made after December 31, 2010), 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 will distribute all available proceeds to the Unit holders after satisfying all existing liabilities of the Trust and establishing adequate reserves for the payment of contingent liabilities.

     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 Alaska 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 Alaska 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 percent of the 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 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.

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’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.

Royalty Production

     The “Royalty Production” for each day in a calendar quarter is 16.4246 percent 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 BP Alaska in the Prudhoe Bay field as of February 28, 1989 (the “BP Working Interests”), or (ii) the actual average daily net production of crude oil and condensate for the quarter from the BP 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 BP 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 Barrel Royalty” for any day is the WTI Price for the day less the sum of (i) Chargeable Costs multiplied by the Cost Adjustment Factor and (ii) Production Taxes.

WTI Price

     The “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”) 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, in each case unaffiliated with BP 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 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 Alaska 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” per barrel of Royalty Production for each calendar year are fixed amounts specified in the Conveyance and do not necessarily represent BP Alaska’s actual costs of production. Chargeable Costs per barrel were $11.25 during 2002, $11.75 during 2003, $12.00 during 2004, $12.25 during 2005 and $12.50 during 2006. Chargeable Costs for 2007 and subsequent years are shown in the following table:

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

Cost Adjustment Factor

     The “Cost Adjustment Factor” for a quarter is the ratio of the Consumer Price Index published for the most recently past February, May, August or November to 121.1 (the Consumer Price Index for January 1989). The “Consumer Price Index” is the U.S. Consumer Price Index, all items and all urban consumers, U.S. city average (1982-84 equals 100), as first published, without seasonal adjustment, by the Bureau of Labor Statistics, Department of Labor, without regard to subsequent revisions or corrections. If the average WTI Price for any calendar quarter falls to $18.00 or less, 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, 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.

Production Taxes

     “Production 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.

     Until August 2006, the Production Taxes payable with respect to the Royalty Production were (i) the Alaska Oil Production Tax (the “Old Tax”), which was levied at the flat rate of 15 percent of the gross value of oil at the point of production (the wellhead or field value) and which, as required by the Conveyance, was applied for the purpose of determining the Royalty Interest without regard to the “economic limit factor” (a formula designed to result in low tax rates for smaller low productive fields and higher tax rates for larger highly productive fields), and (ii) a surcharge of $0.03 per barrel of Royalty Production. The Conveyance provides that, in the case of taxes based upon wellhead or field value, the WTI Price less the product of $4.50 multiplied by the Cost Adjustment Factor is deemed to be the wellhead or field value.

     On August 20, 2006 a new Alaska oil and gas production tax (the “New Tax”) became effective. The New Tax replaced the Old Tax and is retroactive to April 1, 2006. Under the New Tax, producers are taxed on the “production tax value of taxable oil” (gross value at the point of production for the calendar year less the producer’s direct costs of exploring for, developing, or producing oil or gas deposits located within the producer’s leases or properties in Alaska (“Lease Expenditures”) for the year) at a rate equal to the sum of 22.5 percent plus a “progressivity” rate determined by the average monthly production tax value of the oil produced. The progressivity portion of the New Tax is equal to 0.25 percent times the amount by which the simple average for each calendar month of the daily production tax values per barrel of the oil produced during the month exceeds $40 per barrel. In addition, the New Tax increased the surcharge on oil produced from leases or properties in Alaska from $0.03 to $0.04 per barrel.

     In order to resolve uncertainties in the interpretation of the Conveyance resulting from the New Tax, in October 2006 the Trustee entered into a letter agreement with BP Alaska (the “Letter Agreement”), a copy of which is incorporated by reference as Exhibit 4.5 to this report. The Letter Agreement sets forth principles agreed to by BP Alaska and the Trustee to resolve two major issues presented by the New Tax: first, how the amount of the Production Taxes chargeable against the Royalty Interest under the Conveyance is to be determined; and second, the extent, if at all, to which the retroactivity of the New Tax was to be recognized for purposes of computing the Royalty Interest (the “Consensus Principles”).

      Determination of Production Taxes

     The Consensus Principles provide that the amount of Production Taxes (other than the $0.04 per barrel surcharge) chargeable against the Royalty Interest under the Conveyance are to be determined as follows:

     (a) The production tax value per barrel of oil for each day is determined by taking the WTI Price for that day and subtracting the product of the amount of the Chargeable Costs then in effect multiplied by the applicable Cost Adjustment Factor.

     (b) The tax rate for the “progressivity” portion of the New Tax is determined by multiplying 0.25 percent by the amount by which the simple average for each calendar month of the daily production tax values per barrel of oil, determined as described in paragraph (a) above, exceeds $40 per barrel. If that average production tax value per barrel of oil is $40 or less, the “progressivity” rate is zero. The $40 threshold for the applicability of the “progressivity” rate is not subject to adjustment over time.

     (c) The amount of Production Taxes chargeable against the Royalty Interest is determined by multiplying the production tax value per barrel of oil, determined as described in paragraph (a) above, by the Royalty Production under the Conveyance, and then multiplying the product by the percentage rate obtained by adding 22.5 percent to the “progressivity” rate, determined as described in paragraph (b) above.

     The Letter Agreement, incorporated by reference as Exhibit 4.5 to this report, contains a discussion of the rationale for using inflation adjusted Chargeable Costs as a proxy for BP Alaska’s actual Lease Expenditures for purposes of determining Production Taxes chargeable against the Royalty Interest. The Letter Agreement explains that under the New Tax BP Alaska is required to use estimates of Lease Expenditures for purposes of its monthly reporting to the State of Alaska, and that actual Lease Expenditures are determined and reconciled to monthly estimates up to three months after the close of each fiscal year. The use of BP Alaska’s estimated Lease Expenditures for purposes of calculating the Production Taxes applied to quarterly payments of the Royalty Interest could require regular adjustments

to future royalty payments to compensate for over or under charges of Production Taxes to past royalty payments once actual Lease Expenditures were determined. These adjustments could create unfair benefits for certain Unit holders and unfair detriment to others. BP Alaska expects that inflation adjusted Chargeable Costs will provide a reasonable, although not an exact, approximation of BP Alaska’s Leasehold Expenditures and provide certainty to investors in the Trust Units. BP Alaska cautions, however, that to the extent actual Lease Expenditures for a particular year are higher than adjusted Chargeable Costs for the year, the Trust Units may bear Production Taxes at a higher rate than the rate of New Tax applicable to BP Alaska’s production for the year; conversely, if BP Alaska’s Lease Expenditures for a year are less than adjusted Chargeable Costs for that year, Production Taxes charged against the Royalty Interest may be charged at a lower rate than the rate of New Tax applicable to BP Alaska’s production.

      Retroactivity of New Tax

     In the Consensus Principles the parties agreed that the New Tax would not be applied retroactively to payments by BP Alaska with respect to the Royalty Interest. Production Taxes charged against the Royalty Interest were the amount of Old Tax as calculated under the Conveyance for oil production during the period from April 1 to August 19, 2006, inclusive. For oil produced on August 20, 2006 and thereafter, the Production Taxes charged against the Royalty Interest were the amount of New Tax, determined as described above, for that production. The “progressivity” rate under the New Tax for the month of August 2006 was calculated using the average of the daily WTI Prices for the period from August 20 to August 31, 2006, inclusive.

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, 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 Alaska 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 Record 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 payments of estimated liabilities (the “Quarterly Distribution”), 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. 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”) 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). 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).

Reports to Unit Holders

     After the end of each calendar year, the Trustee mails 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 mails Unit holders an annual report containing a copy of this Form 10-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 the 30-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 a non-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 Alaska or a designee of BP Alaska.

Issuance of Additional Units

     The Trust Agreement provides that BP Alaska 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. BP Alaska 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 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”). 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 Alaska or Standard Oil has not been paid to the Trustee, BP will cause BP Alaska 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 Alaska the funds necessary to make such payments. BP is required to make available to BP Alaska and Standard Oil such financial support as BP Alaska, 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 Alaska 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 its affiliates so long as BP remains responsible for ensuring that its obligations are performed in a timely manner.

     BP Alaska 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’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’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 least A- 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’s obligations under the Conveyance and all of BP’s obligations under the Support Agreement).

THE PRUDHOE BAY UNIT AND FIELD

Prudhoe Bay Unit Operation and Ownership

     Since several oil companies besides BP Alaska 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 ChevronTexaco Corporation. The Trust’s Royalty Interest pertains only to production from the BP 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 Alaska 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 Bay Unit Agreement”) and an agreement dated April 1, 1977 among the working interest owners governing Prudhoe Bay Unit operations (the “Prudhoe Bay Unit Operating 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 been the sole operator of the Prudhoe Bay Unit.

     The ownership of the Prudhoe Bay Unit by participating area as of December 31, 2006 is shown in the following table:

     If BP Alaska fails to pay any costs and expenses chargeable to BP Alaska 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 Alaska 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 Alaska or others attributable to BP Alaska’s working interest in the Prudhoe Bay Unit or to the oil produced from it and BP Alaska has agreed to indemnify the Trust and hold it harmless against any such impositions.

     BP Alaska 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 BP Working Interests in the exercise of its reasonable and prudent business judgment without liability to the Trust. BP Alaska also has the right to sell or assign all or any part of the BP 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 productive acres. 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, 2006, approximately 10.9 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”) formations. Underlying the Sadlerochit Group are the oil-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 a gas-oil contact, originally at 8,575 feet below sea level across the main field, and on the bottom by an oil-water contact at approximately 9,000 feet below sea level. A layer of heavy oil and tar overlays the oil-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) 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”). As of December 31, 2006 there were about 1,120 active producing oil wells, 32 gas reinjection wells, 82 water injection wells and 137 water and miscible gas injection wells in the Prudhoe Bay field. Production from the Prudhoe Bay field reached a peak in 1988 and has declined steadily since then. The average well production rate was about 375 barrels per day in 2002, 350 barrels per day in 2003, 317 barrels per day in 2004, 293 barrels per day in 2005 and 223 barrels per day in 2006.

     BP Alaska’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 BP 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 two 34-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 the 48-inch diameter pipeline to Valdez, almost 800 miles (1,287 km) to the south, where it is either loaded onto marine tankers or stored temporarily. It takes the oil about seven days to make the trip. TAPS has a capacity of approximately 1.4 million barrels of oil per day.

     On August 7, 2006, BP announced that BP Alaska had begun a shutdown of the Prudhoe Bay Unit following the discovery of unexpectedly severe corrosion and a small spill from the oil transit line on the eastern side of the field. The decision followed the receipt several days earlier of data from a “smart

pig” ^† run completed in late July. Analysis of the data revealed 16 anomalies in 12 locations in the oil transit line. During follow up inspections of the anomalies, BP Alaska personnel discovered corrosion-related wall thinning which appeared to exceed criteria for continued operation and a leak and small spill estimated at four to five barrels. BP had previously announced plans to replace a three-mile segment of transit line on the western side of the Prudhoe Bay field following inspections conducted after a large spill caused by corrosion discovered in March 2006.

     BP subsequently determined to shut down only the eastern side of the Prudhoe Bay Unit and continue production from the western side of the Unit. The partial shutdown of the field reduced average daily production to approximately half of normal output. On September 22, 2006, BP announced that it had received clearance from the U.S. Department of Transportation to restart production in the eastern half of the Prudhoe Bay Unit. BP has announced plans to completely replace approximately 16 miles of transit lines and to implement federally-required corrosion monitoring practices.

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

     Estimates of proved reserves are inherently imprecise and subjective and are revised over time as additional data become available. Such revisions often may be substantial. BP Alaska’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. Due to the differences in percentages between oil and condensate, the overall share of oil and condensate production allocated to the BP Working Interests will vary over time according to the proportions of hydrocarbon liquid being allocated as condensate or as oil. Under the terms of an Issues Resolution Agreement entered into by the Prudhoe Bay Unit owners in October 1990, the allocation procedures have been 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.

     The reserves attributable to the Trust’s Royalty Interest constitute only a part of the overall reserves allocated to the BP Working Interests. BP Alaska has estimated that the net remaining proved reserves attributable to the Trust as of December 31, 2006 were 81.08 million barrels of oil and condensate, of which 69.02 million barrels are proved developed reserves and 12.06 million barrels are proved undeveloped reserves. Using procedures specified in Financial Accounting Standards Board Statement of Financial Standards No. 69, BP Alaska calculated that as of December 31, 2006 production

of oil and condensate from the proved reserves allocated to the Trust’s Royalty Interest will result in estimated future net revenues to the Trust of $1,855.3 million, with a present value of $1,052.0 million. BP Alaska’s estimates of proved reserves and the estimated future net revenues from the Prudhoe Bay Unit have been reviewed by Miller and Lents, Ltd., independent oil and gas consultants, as set forth in their report following this section.

     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, BP Alaska anticipates that its average net production of oil and condensate from proved reserves will be below 90,000 barrels per day in certain quarters of future years and will fall below 90,000 barrels per day on an annual average basis beginning in 2007. 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 WTI Price of $61.06 per barrel on December 31, 2006, 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 2024. BP Alaska expects continued economic production from the Prudhoe Bay field at a declining rate through 2062.

     There is no precise method of forecasting the allocation of reserve volumes between BP Alaska and 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 BP Working Interests. Rather, reserve volumes attributable to the Trust at any given date are estimated by allocating to the Trust its share of estimated future production from the BP Working Interests based on WTI Prices and other economic parameters in effect on the date of the evaluation.

     The following table shows the net remaining proved reserves of oil and condensate allocated to the BP Working Interests, the net proved reserves allocated to the Trust, and the WTI Prices on the dates indicated:

     The reserve volumes attributable to the Trust are estimated using an allocation of reserve volumes based on estimated future production and the current WTI Price, 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. See Note 10 (unaudited) of the Notes to Financial Statements in Item 8.

     BP Alaska is under no obligation to make investments in development projects which would add additional non-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.

     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.

INDEPENDENT OIL AND GAS CONSULTANTS’ REPORT

		Miller and Lents, Ltd.
		international oil and gas consultants
		founded 1948

February 14, 2007

The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street, 8 West
New York, New York 10286

		Re:		Estimates of Proved Reserves,
				Future Production Rates, and
				Future Net Revenues for the
				BP Prudhoe Bay Royalty Trust
				As of December 31, 2006

Gentlemen:

     This letter report is a summary of investigations performed in accordance with our engagement by you as described in Section 4.8(d) of the Overriding Royalty Conveyance dated February 27, 1989, between BP Exploration (Alaska) Inc. and The Standard Oil Company. The investigations included reviews of the estimates of Proved Reserves and production rate forecasts of oil and condensate made by BP Exploration (Alaska) Inc. attributable to the BP Prudhoe Bay Royalty Trust as of December 31, 2006. Additionally, we reviewed calculations of the resulting Estimated Future Net Revenues and Present Value of Estimated Future Net Revenues attributable to the BP Prudhoe Bay Royalty Trust.

     The estimates and calculations reviewed were summarized in the report prepared by BP Exploration (Alaska) Inc. and transmitted with a cover letter dated February 12, 2007 addressed to Mr. Remo J. Reale of The Bank of New York and signed by Mr. Todd M. Krier. Reviews were also performed by Miller and Lents, Ltd. during this year or in previous years of (1) the procedures for estimating and documenting Proved Reserves, (2) the estimates of in-place reservoir volumes, (3) the estimates of recovery factors and production profiles for the various areas, pay zones, projects, and recovery processes that are included in the estimate of Proved Reserves, (4) the production strategy and procedures for implementing that strategy, (5) the sufficiency of the data available for making estimates of Proved Reserves and production profiles, and (6) pertinent provisions of the Prudhoe Bay Unit Operating Agreement, the Issues Resolution Agreement, the Overriding Royalty Conveyance, the Trust Conveyance, the BP Prudhoe Bay Royalty Trust Agreement, and other related documents referenced in the Form F-3 Registration Statement filed with the Securities and Exchange Commission on August 7, 1989, by BP Exploration (Alaska) Inc.

     Proved Reserves were estimated by BP Exploration (Alaska) Inc. in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a). Estimated Future Net Revenues and Present Value of Estimated Future Net Revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

		Miller and Lents, Ltd.
The Bank of New York				February 14, 2007
Trustee, BP Prudhoe Bay Royalty Trust

     The Prudhoe Bay (Permo-Triassic) Reservoir is defined in the Prudhoe Bay Unit Operating Agreement. The Prudhoe Bay Unit is an oil and gas unit situated on the North Slope of Alaska. The BP Prudhoe Bay Royalty Trust is entitled to a royalty payment on 16.4246 percent of the first 90,000 barrels of the actual average daily net production of oil and condensate for each calendar quarter from the BP Exploration (Alaska) Inc. working interest as defined in the Overriding Royalty Conveyance. The payment amount depends upon the Per Barrel Royalty which in turn depends upon the West Texas Intermediate Price, the Chargeable Costs, the Cost Adjustment Factor, and Production Taxes, all of which are defined in the Overriding Royalty Conveyance. “Barrel” as used herein means Stock Tank Barrel as defined in the Overriding Royalty Conveyance.

     Our reviews do not constitute independent estimates of the reserves and annual production rate forecasts for the areas, pay zones, projects, and recovery processes examined. We relied upon the accuracy and completeness of information provided by BP Exploration (Alaska) Inc. with respect to pertinent ownership interests and various other historical, accounting, engineering, and geological data.

     As a result of our cumulative reviews, based on the foregoing, we conclude that:

	1.		A large body of basic data and detailed analyses are available and were used in making the estimates. In our judgment, the quantity and quality of currently available data on reservoir boundaries, original fluid contacts, and reservoir rock and fluid properties are sufficient to indicate that any future revisions to the estimates of total original in-place volumes should be minor. Furthermore, the data and analyses on recovery factors and future production rates are sufficient to support the Proved Reserves estimates.
	2.		The methods and procedures employed to accumulate and evaluate the necessary information and to estimate, document, and reconcile reserves, annual production rate forecasts, and future net revenues are effective and are in accordance with generally accepted geological and engineering practice in the petroleum industry.
	3.		Based on our limited independent tests of the computations of reserves, production flowstreams, and future net revenues, such computations were performed in accordance with the methods and procedures described to us.
	4.		The estimated net remaining Proved Reserves attributable to the BP Prudhoe Bay Royalty Trust as of December 31, 2006, of 81.08 million barrels of oil and condensate are, in the aggregate, reasonable. Of the 81.08 million barrels of total Proved Reserves, 69.02 million barrels are Proved Developed Reserves, and 12.06 million barrels are Proved Undeveloped Reserves.
	5.		Utilizing the specified procedures outlined in Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69, BP Exploration (Alaska) Inc. calculated that as of December 31, 2006 production of the Proved Reserves will result in Estimated Future Net Revenues of $1,855.3 million and Present Value of Estimated Future Net Revenues of $1,052.0 million to the BP Prudhoe Bay Royalty Trust. These estimates are reasonable.
	6.		Temporary oil transport bypass lines, installed following the production disruptions of 2006, did not recover full production capacity in the field. This condition is expected to continue into 2007. In July 2006, a number of wells were shut-in that did not conform to the well

		Miller and Lents, Ltd.
The Bank of New York				February 14, 2007
Trustee, BP Prudhoe Bay Royalty Trust

			integrity standards of BP Exploration (Alaska) Inc. and this also had the impact of reducing production capacity. BP Exploration (Alaska) Inc. is now in action on pipeline replacement and a well work program to recover this production capacity.
	7.		BP Exploration (Alaska) Inc. has undertaken a program of field-wide infrastructure renewal, pipeline replacement, and well mechanical improvements. As a consequence of these activities and their required downtime, BP Exploration (Alaska) Inc. anticipates that its net production of oil and condensate from Proved Reserves will be below 90,000 barrels per day in certain quarters of future years and will fall below 90,000 barrels per day on an annual average basis beginning in 2007. The BP Exploration (Alaska) Inc. projection of its net production of oil and condensate under its forecast of downtime and operating efficiency is reasonable. Production attributable to the BP Prudhoe Bay Royalty Trust will decline with the BP Exploration (Alaska) Inc. production. However, the Per Barrel Royalty will not have a positive value if the West Texas Intermediate Price is less than the sum of the per barrel Chargeable Costs and per barrel Production Taxes, appropriately adjusted in accordance with the Overriding Royalty Conveyance. Under such circumstances, average daily production attributable to the BP Prudhoe Bay Royalty Trust will have no value and therefore will not contribute to the reserves regardless of BP Exploration (Alaska) Inc.’s net production level.
	8.		Based on the West Texas Intermediate Price of $61.06 per barrel on December 31, 2006, current Production Taxes, and the Chargeable Costs adjusted as prescribed by the Overriding Royalty Conveyance, the projection that royalty payments will continue through the year 2024 is reasonable. BP Exploration (Alaska) Inc. expects continued economic production at a declining rate through the year 2062; however, for the economic conditions and production forecast as of December 31, 2006 the Per Barrel Royalty will be zero following the year 2024. Therefore, no reserves are currently attributed to the BP Prudhoe Bay Royalty Trust after that date.
	9.		Even if expected reservoir performance does not change, the estimated reserves, economic life, and future revenues attributable to the BP Prudhoe Bay Royalty Trust may change significantly in the future. This may result from changes in the West Texas Intermediate Price or from changes in other prescribed variables utilized in calculations defined by the Overriding Royalty Conveyance.

     Estimates of ultimate and remaining reserves and production scheduling depend upon assumptions regarding expansion or implementation of alternative projects or development programs and upon strategies for production optimization. BP Exploration (Alaska) Inc. has continual reservoir management, surveillance, and planning efforts dedicated to (1) gathering new information, (2) improving the accuracy of its reserves and production capacity estimates, (3) recognizing and exploiting new opportunities, (4) anticipating potential problems and taking corrective actions, and (5) identifying, selecting, and implementing optimum recovery program and cost reduction alternatives. Given this significant effort and ever-changing economic conditions, estimates of reserves and production profiles will change periodically.

     The current estimate of Proved Reserves includes only those projects or development programs that are deemed reasonably certain to be implemented, given current economic and regulatory conditions. Future projects, development programs, or operating strategies different from those assumed in the current estimates may change future estimates and affect recoveries. However, because several complementary and alternative projects are being considered for recovery of the remaining oil in the

		Miller and Lents, Ltd.
The Bank of New York				February 14, 2007
Trustee, BP Prudhoe Bay Royalty Trust

reservoir, a decision not to implement a currently planned project may allow scope expansion or implementation of another project, thereby increasing the overall likelihood of recovering the reserves.

     Future production rates will be controlled by facilities limitations and upsets, well downtime, and the effectiveness of programs to optimize production and costs. BP Exploration (Alaska) Inc. currently expects continued economic production from the reservoir at a declining rate through the year 2062. Additional drilling, workovers, facilities modifications, new recovery projects, and programs for production enhancement and optimization are expected to mitigate but not eliminate the decline in gross oil and condensate production capacity.

     In making its future production rate forecasts, BP Exploration (Alaska) Inc. provided for anticipated downtime and planned facilities upsets. Although allowances for unplanned upsets are also considered in the estimates, the studies do not provide for any impediments to crude oil production as a consequence of major disruptions.

     Under current economic conditions, gas from the Alaskan North Slope, except for minor volumes, cannot be marketed commercially. Oil and condensate recoveries are expected to be greater as a result of continued reinjection of produced gas than the recoveries would be if major volumes of produced gas were being sold. No major gas sale is assumed in the current estimates. If major gas sales are undertaken in the future, BP Exploration (Alaska) Inc. estimates that such sales would not actually commence until ten to eleven years in the future. In the event that major gas sales are initiated, ultimate oil and condensate recoveries may be reduced from the current estimates unless recovery projects other than those included in the current estimates are implemented.

     Large volumes of natural gas liquids are likely to be produced and marketed in the future whether or not major gas sales become viable. Natural gas liquids reserves are not included in the estimates cited herein. The BP Prudhoe Bay Royalty Trust is not entitled to royalty payments from production or sales of natural gas or natural gas liquids.

     The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those reflected in this study or disruption of existing transportation routes or facilities may cause the total quantity of oil or condensate to be recovered, actual production rates, prices received, or operating and capital costs to vary from those reviewed in this report.

		Miller and Lents, Ltd.
The Bank of New York				February 14, 2007
Trustee, BP Prudhoe Bay Royalty Trust

     Miller and Lents, Ltd., is an independent oil and gas consulting firm. None of the principals of this firm have any direct financial interests in BP Exploration (Alaska) Inc. or its parent or any related companies or in the BP Prudhoe Bay Royalty Trust. Our fee is not contingent upon the results of our work or report, and we have not performed other services for BP Exploration (Alaska) Inc. or the BP Prudhoe Bay Royalty Trust that would affect our objectivity.

WPK/sg

INDUSTRY 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’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 Alaska 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 Alaska has advised that the existence of legislation and regulation has had no material adverse effect on BP Alaska’s current method of operations, the effect of future legislation and regulations cannot be predicted.

     On December 29, 2006, the President signed into law the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act”), which extends the U.S. Department of Transportation’s oversight to include oil and gas pipelines operating at low pressures. The PIPES Act makes the oil transit lines in the Prudhoe Bay field subject to federal supervision and inspection. 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 Alaska 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.

     The Trust makes quarterly distributions 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”) is subject to tax on the gross income produced by the Royalty Interest at a rate equal to 30 percent (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 percent 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 28 percent of any reportable payment if the payee fails to furnish his taxpayer identification number (“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.

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 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.

ITEM 1A. RISK FACTORS

     Owners of Units are exposed to risks and uncertainties that are particular to their investment. This Item describes several such risks and uncertainties, but not necessarily all of them.

•

Royalty Production from the Prudhoe Bay field is projected to decline and will eventually cease.

     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. Royalty payments to the Trust are projected to cease after 2024. Production estimates included in this report are based on economic conditions and production forecasts as of the end of 2006, and also depend on various assumptions, projections and estimates which are continually revised and updated by BP Alaska. These revisions could result in material changes to the projected declines in production. It is possible that economic production from the reserves allocated to the BP Working Interests could decline more quickly and end sooner than is currently projected, especially if construction of a gas pipeline makes it economical to produce natural gas from the Prudhoe Bay field, as discussed in the following paragraphs.

•

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

     In February 2006, the then Governor of Alaska, Frank Murkowski, announced that the State and BP Alaska, ConocoPhilips and Exxon Mobil had reached agreement in principle on a contract to build a natural gas pipeline which would run from Alaska’s North Slope through Canada and into the Midwestern United States. The Alaska legislature failed to approve the proposed contract during the 2006 legislative session, and Governor Murkowski left office at the end of 2006 without the contract having been executed. The new Governor, Sarah Palin, has announced her intention to introduce a bill in March 2007 which will reopen bidding to construct the proposed gas pipeline and set project criteria that energy companies must meet in exchange for inducement incentives from the State to build the pipeline. Construction of a gas pipeline from the North Slope to the continental United States is estimated to take up to ten years.

     Without a pipeline, extraction of natural gas from the Prudhoe Bay field is not economical. 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. If the proposed natural gas pipeline is constructed, it will make it economical to extract natural gas from the Prudhoe Bay field and transport it to the lower 48 states for sale. Extraction of natural gas from the Prudhoe Bay field will lower reservoir pressure. The lowering of the reservoir pressure may accelerate the decline in production from the BP Working Interests and the time at which royalty payments to the Trust will cease. Since the Trust is not entitled to any royalty payments with respect to natural gas production from the BP Working Interests, the Unit holders will not realize any offsetting benefit from natural gas production from the Prudhoe Bay field.

•

Royalty payments by BP Alaska to the Trust are unpredictable, because they depend directly on world crude oil prices which have been volatile in recent years.

     During the past decade, crude oil prices have been very volatile. Crude oil prices increased continuously from 2001 to mid-year 2006, with the WTI Price having reached a high of over $77 per barrel during July 2006, before declining to approximately $61 per barrel at year-end. Before 2002, though, crude oil prices went through a period of extreme volatility. In late 1998 and early 1999, spot oil prices fell to a historic lows, reaching between $10 and $11 per barrel in December 1998. As a result, the

average WTI Price during the fourth quarter of 1998 and the first quarter of 1999 fell below the total adjusted Chargeable Costs and Production Taxes chargeable against Royalty Production and the Trust did not receive royalty distributions from BP Alaska during the first two quarters of 1999.

     Recent moves in crude oil prices have been affected by many factors, including changes in demand by oil-consuming countries, the actions of OPEC to control production by members of the cartel, shifts in inventory management strategies by international oil companies, conservation measures by consumers, increasing effects of the oil futures market, and other unpredictable political, psychological and economic factors such as the war in Iraq and tensions with Iran over its nuclear program. Future domestic and international events and conditions may produce wide swings in crude oil prices over relatively short periods of time. Unit holders thus are subject to the risk that cash distributions with respect to their Units may vary widely from quarter to quarter.

•

Prudhoe Bay field oil production could be shut in partially or entirely from time to time as a result of damage to or failures of field pipelines or equipment.

     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. As a result of the shutdown, average net production from the BP Working Interests fell below 90,000 barrels per day in both the third and fourth quarters of 2006 and royalty payments received by the Trust from BP Alaska in October 2006 and January 2007 were adversely affected. 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 has announced plans to completely replace approximately 16 miles of transit lines and to implement 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.

•

Oil production from the Prudhoe Bay Unit could be interrupted by damage to the Trans-Alaska Pipeline System from natural disasters, accidents, or deliberate attacks.

     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 accidental damage and deliberate attacks. If the pipeline or its pumping stations should suffer major damage from natural or man-made causes, production from the Prudhoe Bay Unit could be shut in until the pipeline system can be repaired and restarted. 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.

•

Production from the BP Working Interests may be interrupted or discontinued by BP Alaska.

     BP Alaska has no obligation to continue production from the BP Working Interests or to maintain production at any level and may interrupt or discontinue production at any time. The Trust does not have the right to take over operation of the BP Working Interests or share in any operating decisions by BP Alaska concerning the Prudhoe Bay Unit. The operation of the Prudhoe Bay Unit is subject to normal operating hazards incident to the production and transportation of oil in Alaska. In the event of damage to the infrastructure, facilities and equipment in the Prudhoe Bay field which is covered by insurance, BP

Alaska has no obligation to use insurance proceeds to repair such damage and may elect to retain such proceeds and close damaged areas to production.

•

There are potential conflicts of interest between BP Alaska and the Trust that could affect the royalties paid to Unit holders.

     The interests of BP Alaska and the Trust with respect to the Prudhoe Bay Unit could at times be different. The Per Barrel Royalty that BP Alaska pays to the Trust is based on the WTI Price and Chargeable Costs, both of which are amounts contractually defined the Conveyance. The WTI Price does not necessarily correspond to the actual price realized by BP Alaska for crude oil produced from the BP Working Interests, and Chargeable Costs may not bear any relation to BP Alaska’s actual costs of production. The actual per barrel profit realized by BP Alaska 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’s actual per barrel revenues and costs could be such that BP Alaska might determine to interrupt or discontinue production in whole or in part from the BP Working Interests even though a Per Barrel Royalty might otherwise be payable to the Trust under the Conveyance.

ITEM 1B. UNRESOLVED STAFF COMMENTS

     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 Exchange Act that remain unresolved.

amounts to be proven at trial, punitive damages, reasonable costs and expenses incurred in the action, including counsel fees and expert fees, and an injunction to enforce the Support Agreement by requiring the defendants to perform their obligations thereunder, including seeking financial support from BP for the payment of cash distributions to Unit holders with respect to the Royalty Interest in amounts lost due to disruption of production from the Prudhoe Bay Unit.

     The litigation is in its early stages. The action has not been certified by the Court as a class action.

     On January 11, 2007, the Trustee authorized counsel to appear in the action on behalf of the Trust. On February 28, 2007, the Trust moved to dismiss the Complaint on the ground that the Complaint fails to state a claim upon which relief can be granted against the Trust.

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 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. Interest income received by the Trust from the investment of the reserve fund is added to the distributions received from BP Alaska and paid to the Unit holders on each Quarterly Record Date.

     Annual decreases in Trust Corpus and total assets are the result of amortization of the Royalty Interest. See Notes 2 and 3 of Notes to Financial Statements in Item 8.

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’s operations during the twelve-month period ended on the preceding September 30.

     As long as BP Alaska’s average net production of oil and condensate per quarter from the BP 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. See “THE PRUDHOE BAY UNIT AND FIELD – Collection and Transportation of Prudhoe Bay Oil” in Item 1 for information concerning the recent partial shutdown of the Prudhoe Bay field, which resulted in average net production falling below 90,000 barrels a day during the third and fourth quarters of 2006. BP Alaska has advised the Trustee that it estimates that average net production from the BP Working Interests will fall below 90,000 barrels a day on an annual basis beginning in 2007 as a result of field-wide infrastructure renewal activities.

     BP Alaska estimates Royalty Production from the BP 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 BP Working Interests is below 90,000 barrels per day in 2007 and future years, calculation by BP Alaska of actual Royalty Production data may result in revisions of prior Royalty Production estimates. Revisions by BP Alaska of its Royalty Production calculations may result in quarterly royalty payments by BP Alaska which reflect adjustments for overpayments or underpayments of royalties with respect to prior quarters. Such adjustments, if material, may adversely affect certain Unit holders who buy or sell Units between the Quarterly Record Dates for the Quarterly Distributions affected.

     The Quarterly Distribution paid by the Trust to Unit holders in January 2007 included $1,736,264 received by the Trust which represented the amount of an underpayment by BP Alaska (plus interest on

the underpayment) of the royalty payment due in October 2006 with respect to the quarter ended September 30, 2006. See Note 8 of Notes to Financial Statements in Item 8. Because the statement of cash earnings and distributions of the Trust is prepared on a modified cash basis, royalty revenues for the year ended December 31, 2006 do not include the amount of the October 2006 underpayment.

     During the years 2005 and 2006 and the period of 2007 up to the date of this report, WTI Prices have been above 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 2007 will depend on WTI Prices prevailing during the remainder of the year.

2006 compared to 2005

     Continuing increases in world oil prices drove WTI Prices higher in the fourth quarter of 2005 and the first three quarters of 2006 (the period on which calendar 2006 cash basis revenues were based). WTI Prices averaged 23.5% higher during that period than during the twelve months ended September 30, 2005. As a result, royalty revenues and cash distributions during 2006 rose approximately 21% from 2005, even though revenues were adversely affected by the partial shutdown of the Prudhoe Bay Unit in August 2006. The shutdown was primarily responsible for royalty revenues in the fourth quarter of 2006 falling approximately 27% from average royalty revenues during the first three quarters of the year. Chargeable Costs per barrel increased from $12.25 to $12.50, beginning in the first quarter of 2006. The increase in Chargeable Costs, continued increases in the Cost Adjustment Factor and increases in Production Taxes (which, during the quarter ended September 30, 2006, reflected the new Alaska oil and gas production tax which became effective in August 2006) further reduced the effect of increases in WTI Prices on the Trust’s revenues in 2006.

2005 compared to 2004

     Increases in world oil prices resulted in higher WTI Prices in the fourth quarter of 2004 and the first three quarters of 2005 (the period on which calendar 2005 cash basis revenues were based). WTI Prices averaged 44% higher during that period than during the twelve months ended September 30, 2004. As a result, royalty revenues during 2005 rose approximately 85% from 2004, and cash distributions rose approximately 86%. Chargeable Costs per barrel increased from $12.00 to $12.25, beginning in the first quarter of 2005. The increase in Chargeable Costs, continued increases in the Cost Adjustment Factor and increases in Production Taxes (which averaged approximately 52.5% higher during the twelve months ended September 30, 2005 than in the prior twelve-month period) attenuated the effect of the increase in WTI Prices on the Trust’s revenues in 2005.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

BP PRUDHOE BAY ROYALTY TRUST

Index To Financial Statements

		Page
Report of Independent Registered Public Accounting Firm		35
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2006 and 2005		36
Statements of Cash Earnings and Distributions for the years ended December 31, 2006, 2005 and 2004		37
Statements of Changes in Trust Corpus for the years ended December 31 2006, 2005 and 2004		38
Notes to Financial Statements		39

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Trustee and Holders of Trust Units of BP Prudhoe Bay Royalty Trust:

We have audited the accompanying statements of assets, liabilities, and trust corpus of BP Prudhoe Bay Royalty Trust (the “Trust”) as of December 31, 2006 and 2005, and the related statements of cash earnings and distributions and changes in trust corpus for each of the years in the three-year period ended December 31, 2006. These financial statements are the responsibility of The Bank of New York, as the Trust’s trustee (the “Trustee”). Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the trustee, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of the trust as of December 31, 2006 and 2005 and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2006 in conformity with the modified cash basis of accounting described in Note 2.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2007 expressed an unqualified opinion on the trustee’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Dallas, Texas

March 1, 2007

See accompanying notes to financial statements.

See accompanying notes to financial statements.

See accompanying notes to financial statements.

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2006

(1) Formation of the Trust and Organization

BP Prudhoe Bay Royalty Trust (the “Trust”), a grantor trust, was created as a Delaware statutory trust pursuant to a Trust Agreement dated February 28, 1989 among the Standard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”), The Bank of New York (The “Trustee”) and The Bank of New York (Delaware), as co-trustee. Standard Oil and BP Alaska are indirect wholly owned subsidiaries of the BP p.l.c. (“BP”).

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

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

The trustees of the Trust are The Bank of New York, a New York corporation authorized to do a banking business, and The Bank of New York (Delaware), a Delaware banking corporation. The Bank of New York (Delaware) serves as co-trustee in order to satisfy certain requirements of the Delaware Trust Act. The Bank of New York alone is able to exercise the rights and powers granted to the Trustee in the Trust Agreement.

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

The Trust is passive, with the Trustee having only such powers as are necessary for the collection and distribution of revenues, the payment of Trust liabilities, and the protection of the Royalty Interest. The Trustee, subject to certain conditions, is obligated to establish cash reserves and borrow funds to pay liabilities of the Trust when they become due. The Trustee may sell Trust properties only (a) as authorized by a vote of the Trust Unit Holders, (b) when necessary to provide for the payment of specific liabilities of the Trust then due (subject to certain conditions) or (c) upon termination of the Trust. Each Trust Unit issued and outstanding represents an equal undivided share of beneficial interest in the Trust. Royalty payments are received by the Trust and distributed to Trust Unit holders, net of Trust expenses, in the month succeeding the end of each calendar quarter. The Trust will terminate upon the first to occur of the following events:

	a.		On or prior to December 31, 2010: upon a vote of Trust Unit Holders of not less than 70% of the outstanding Trust Units.
	b.		After December 31, 2010: (i) upon a vote of Trust Unit Holders of not less than 60% of the outstanding Trust Units, or (ii) at such time the net revenues from the Royalty Interest for two

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2006

successive years commencing after 2010 are less than $1,000,000 per year (unless the net revenues during such period are materially and adversely affected by certain events).

In order to ensure the Trust has the ability to pay future expenses, the Trust established a cash reserve account which the Trustee believes is sufficient to pay approximately one year’s current and expected liabilities and expenses of the Trust.

(2) Basis of Accounting

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

	a.		Revenues are recorded when received (generally within 15 days of the end of the preceding quarter) and distributions to Trust Unit Holders are recorded when paid.
	b.		Trust expenses (which include accounting, engineering, legal, and other professional fees, trustees’ fees, and out-of-pocket expenses) are recorded on an accrual basis.
	c.		Cash reserves may be established by the Trustee for certain contingencies that would not be recorded under generally accepted accounting principles.
	d.		Amortization of the Royalty Interest is calculated based on the units of production method. Such amortization is charged directly to the Trust Corpus, and does not affect cash earnings. The daily rate for amortization per net equivalent barrel of oil for the years ended December 31, 2006, 2005 and 2004 was $0.41, $0.37 and $0.37, respectively. The Trust evaluates impairment of the Royalty Interest by comparing the undiscounted cash flows expected to be realized from the Royalty Interest to the carrying value, pursuant to Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the Royalty Interest.

While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful because quarterly distributions to the Trust Unit Holders are based on net cash receipts. The accompanying modified cash basis financial statements contain all adjustments necessary to present fairly the assets, liabilities and Corpus of the Trust as of December 31, 2006 and 2005, and the modified cash earning and distributions and changes in Trust Corpus for the years ended December 31, 2006, 2005 and 2004. The adjustments are of a normal recurring nature and are, in the opinion of the Trustee, necessary to fairly present the results of operations.

As of December 31, 2006 and 2005, cash equivalents which represent the cash reserve consist of U.S. treasury bills with an initial term of less than three months.

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

(4) Income Taxes

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

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

(5) Alaska Oil and Gas Production Tax

On August 20, 2006 a new Alaska oil and gas production tax (the “New Tax”) became effective. The New Tax replaced an oil production tax levied at the flat rate of 15% of the gross value at the point of production of taxable oil produced from a producer’s leases or properties in the State of Alaska and is retroactive to April 1, 2006.

Under the New Tax, producers are taxed on the “production tax value of taxable oil” (gross value at the point of production for the calendar year less the producer’s direct costs of exploring for, developing, or producing oil or gas deposits located within the producer’s leases or properties in Alaska for the year) at a rate equal to the sum of 22.5% plus a “progressivity” rate determined by the average monthly production tax value of the oil produced. The progressivity portion of the New Tax is equal to 0.25% times the amount by which the simple average for each calendar month of the daily taxable values per barrel of the oil produced during the month exceeds $40 per barrel.

The Trustee and BP Alaska entered into a letter agreement (the “Letter Agreement”) to resolve the major issues associated with the New Tax. The Letter Agreement modified the calculation of Production Taxes in the daily Per Barrel Royalty calculation effective as of August 20, 2006. It also provides that the retroactivity provisions of the New Tax are not applicable to the Per Barrel Royalty calculation for periods prior to August 20, 2006.

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2006

(6) Partial Shutdown of Prudhoe Bay Oil Field

On August 7, 2006, BP announced that BP Alaska had commenced a shutdown of the Prudhoe Bay Field as a result of the discovery of unexpectedly severe corrosion and a small spill from an oil transit line in the Prudhoe Bay Field. BP subsequently determined to shut down only the Eastern Operating Area of the field and continue production from the Western Operating Area. Clearance from the U.S. Department of Transportation to restart production in the Eastern Operating Area was received in September 2006.

(7) Litigation Contingency

In November 2006, a Unit holder of the Trust filed a complaint in the United States District Court for the District of Alaska, purportedly on behalf of a class consisting of all Unit holders of the Trust. The complaint asserts claims against BP, BP Alaska, the Trust and The Standard Oil Company (“Standard Oil”) relating to the shutdown of the Prudhoe Bay field and arising out of the Support Agreement dated February 28, 1989 among BP, BP Alaska, Standard Oil and the Trust. The Trust will incur expenses in connection with the defense of this action, including expenses related to the retention of counsel and of consultants. The Trustee is unable to estimate such expenses, but such expenses may be substantial.

(8) Subsequent Event

On January 16, 2007, the Trust received a payment of $43,205,572 from BP Alaska. This payment consisted of $41,469,307, representing the royalty payment due with respect to the Trust’s Royalty Interest for the quarter ended December 31, 2006, plus $1,736,264, representing the amount of an underpayment by BP Alaska, including interest on the underpayment, of the royalty payment due with respect to the quarter ended September 30, 2006. The royalty payment of $36,144,998 with respect to the third quarter of 2006, which the Trust received on October 16, 2006, was calculated based on estimated average net production of crude oil and condensate during the third quarter of 2006 of approximately 59,300 barrels per day. Actual average net production of crude oil and condensate during the quarter was approximately 62,087 barrels per day. On the basis of the actual production data, the royalty payment owed by BP Alaska with respect to the quarter ended September 30, 2006 was $37,881,262.

(9) Summary of Quarterly Results (Unaudited)

A summary of selected quarterly financial information for the years ended December 31, 2006, 2005, and 2004 is as follows (in thousands, except unit data):

(10) Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Reserves (Unaudited)

Pursuant to Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities (“FASB 69”), the Trust is required to include in its financial statements supplementary information regarding estimates of quantities of proved reserves attributable to the Trust and future net cash flows.

Estimates of proved reserves are inherently imprecise and subjective and are revised over time as additional data becomes available. Such revisions may often be substantial. Information regarding estimates of proved reserves attributable to the combined interests of BP Alaska and the Trust were based on reserve estimates prepared by BP Alaska. BP Alaska’s reserve estimates are believed to be reasonable and consistent with presently known physical data concerning the size and character of the Field.

There is no precise method of allocating estimates of physical quantities of reserve volumes between BP Alaska and the Trust, since the Royalty Interest is not a working interest and the Trust does not own and is not entitled to receive any specific volume of reserves from the Field. Reserve volumes attributable to the Trust were estimated by allocating to the Trust its share of estimated future production from the Field, based on the WTI Price on December 31, 2006 ($61.06 per barrel),

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2006

December 31, 2005 ($61.04 per barrel) and December 31, 2004 ($43.46 per barrel). Because the reserve volumes attributable to the Trust are estimated using an allocation of reserve volumes based on the estimated future production and on the current WTI Price, a change in the timing of estimated production or a change in the WTI price will result in a change in the Trust’s estimated reserve volumes. Therefore, the estimated reserve volumes attributable to the Trust will vary if different production estimates and prices are used.

In addition to production estimates and prices, reserve volumes attributable to the Trust are affected by the amount of Chargeable Costs that will be deducted in determining the Per Barrel Royalty. Net proved reserves of oil and condensate attributable to the Trust as of December 31, 2006, 2005 and 2004, based on BP Alaska’s latest reserve estimate at such time and the WTI Prices on December 31, 2006, 2005 and 2004, were estimated to be 81, 85 and 77 million barrels, respectively (of which 69, 73 and 68 million barrels, respectively, are proved developed). Under the provisions of FASB 69, no consideration can be given to reserves not considered proved at the present time.

The standardized measure of discounted future net cash flow relating to proved reserves disclosure required by FASB 69 assigns monetary amounts to proved reserves based on current prices. This discounted future net cash flow should not be construed as the current market value of the Royalty Interest. A market valuation determination would include, among other things, anticipated price changes and the value of additional reserves not considered proved at the present time or reserves that may be produced after the currently anticipated end of field life. At December 31, 2006, 2005 and 2004, the standardized measure of discounted future net cash flow relating to proved reserves attributable to the Trust (estimated in accordance with the provisions of FASB 69), based on the WTI Prices on those dates of $61.06, 61.04 and $43.46, respectively, were as follows (in thousands):

Internal Control Over Financial Reporting

      Management’s Annual Report on Internal Control Over Financial Reporting. The Bank of New York, as Trustee of the Trust, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). Based on the Trustee’s evaluation under the COSO criteria, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2006.

     The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report set forth in full below.

that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the trustee’s assessment that BP Prudhoe Bay Royalty Trust maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, BP Prudhoe Bay Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities, and trust corpus of BP Prudhoe Bay Royalty Trust as of December 31, 2006 and 2005, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2006, and our report dated March 1, 2007 expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described the trust’s method of accounting as explained in Note 2 to the financial statements.

KPMG LLP

Dallas, Texas

March 1, 2007

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

     The Trust has not adopted a code of ethics. The standards of conduct governing the Trustee are set forth in the Trust Agreement and Delaware law. Ethical standards applicable to the employees of the Trustee are set forth in The Bank of New York’s Code of Conduct which may be found at www.bankofny.com .

     There is no audit committee or committee performing comparable functions responsible for reviewing the audited financial statements of the Trust.

Unit Ownership of Management

     Neither BP Alaska, Standard Oil, nor BP owns any Units. No Units are owned by The Bank of New York, as Trustee or in its individual capacity, or by The Bank of New York (Delaware), as co-trustee or in its individual capacity.

Changes in Control

     The Trustee knows of no arrangement, including the pledge of Units, the operation of which may at a subsequent date result in a change in control of the Trust.

(b) FINANCIAL STATEMENT SCHEDULES

     All financial statement schedules have been omitted because they are either not applicable, not required or the information is set forth in the financial statements or notes thereto.

(c) EXHIBITS

4.1		BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee.
4.2		Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc. and The Standard Oil Company.
4.3		Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay Royalty Trust.
4.4		Support Agreement dated as of February 28, 1989, as amended May 8, 1989, among The British Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.
4.5		Letter agreement dated October 13, 2006 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee.
31		Rule 13a-14(a) certification.
32		Section 1350 certification.

SIGNATURES

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

		BP PRUDHOE BAY ROYALTY TRUST
		By: THE BANK OF NEW YORK, as Trustee
		By:		/s/ Remo Reale
				Remo Reale
				Vice President

March 1, 2007

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

INDEX TO EXHIBITS