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  **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, 2008****OR**   o **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934****Commission File Number 1-10243****BP PRUDHOE BAY ROYALTY TRUST**(Exact name of registrant as specified in its charter)   **DELAWARE**  State or other jurisdiction **13-6943724**of incorporation or organization) (I.R.S. Employer Identification No.)   **THE BANK OF NEW YORK MELLON, TRUSTEE**  **101 BARCLAY STREET**  **NEW YORK, NEW YORK** **10286**(Address of principal executive offices) (Zip Code)Registrant’s telephone number, including area code: (212) 815-6908Securities 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 Rule405 of the Securities Act.     Yes þ No o     Indicate by check mark if the registrant is not required to file reports pursuant to Section13 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 filedby Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (orfor such shorter period that the registrant was required to file such reports), and (2) has beensubject 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 RegulationS-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, indefinitive proxy or information statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K.     þ     Indicate by check mark whether the registrant is a large accelerated filer, an acceleratedfiler, a non-accelerated filer or a smaller reporting company. See the definitions of “largeaccelerated filer,” accelerated filer” and “smaller reporting company” in Rule 12b-2 of theExchange Act. (Check one):   Large Accelerated filerþ Accelerated filer oNon-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 ofthe Exchange Act     Yes o No þ     The aggregate market value of Units held by nonaffiliates (computed by reference to theclosing sale price in New York Stock Exchange transactions on June 30, 2008 (the last business dayof the registrant’s most recently completed second fiscal quarter) was approximately$2,211,904,000.     As of February 27, 2009, 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  12        THE BP SUPPORT AGREEMENT  13        THE PRUDHOE BAY UNIT AND FIELD  14        INDEPENDENT OIL AND GAS CONSULTANTS’ REPORT  20        INDUSTRY CONDITIONS AND REGULATIONS  25        CERTAIN TAX CONSIDERATIONS  25        ITEM 1A. RISK FACTORS  28        ITEM 1B. UNRESOLVED STAFF COMMENTS  31        ITEM 2. PROPERTIES  31        ITEM 3. LEGAL PROCEEDINGS  31        ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 31           PART II  31        ITEM 5. MARKET FOR REGISTRANT’S UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS  31        ITEM 6. SELECTED FINANCIAL DATA  32        ITEM 7. TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS  32        ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK  35        ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA  36        ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE  49        ITEM 9A. CONTROLS AND PROCEDURES  49        ITEM 9B. OTHER INFORMATION  51        PART III  51        ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE  51  EX-31 EX-32 i 
 

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       ITEM 11. EXECUTIVE COMPENSATION  52        ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS  52        ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE  53        ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES  53        ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES  53        SIGNATURES  55  ii 
 

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**PART I****ITEM 1.** **BUSINESS****INTRODUCTION**     BP Prudhoe Bay Royalty Trust (the “Trust”) was created as a Delaware business trust by the BPPrudhoe Bay Royalty Trust Agreement dated February 28, 1989 (the “Trust Agreement”) among TheStandard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”), The Bank of NewYork Mellon (formerly named The Bank of New York), as trustee (the “Trustee”), and F. JamesHutchinson, co-trustee (BNY Mellon Trust of Delaware, formerly named The Bank of New York(Delaware), successor co-trustee). BP Alaska and Standard Oil are wholly owned subsidiaries of BPp.l.c. (“BP”). The Trustee’s corporate trust offices are located at 101 Barclay Street, New York,New York 10286 and its telephone number is (212) 815-6908.     The Trust electronically files annual reports on Form 10-K, quarterly reports on Form 10-Qand, when certain events require them, current reports on Form 8-K with the Securities and ExchangeCommission (“SEC”). The public may read and copy any materials filed by the Trust with the SEC atthe SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public mayobtain information on the operation of the Public Reference Room by calling the SEC at1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy andinformation statements, and other information regarding issuers (including the Trust) that fileelectronically with the SEC. The address of the SEC’s website is http://www.sec.gov.     The Trust does not maintain an Internet website, but certain information concerning the Trustand the Trust Units may be obtained from the BusinessWire website at the following page location:http://www.businesswire.com/portal/site/home/news/company?vnsId=41701 . The Trustee willprovide paper or electronic copies of the Trust’s reports on Form 10-K, Form 10-Q and Form 8-K, andamendments to those reports, free of charge upon request as soon as reasonably practicable afterthe Trust files them with the SEC. Requests for copies of reports may be made by mail to: The Bankof New York Mellon, 101 Barclay Street, Floor 8W, New York, NY 10286, Attention: Mr. GeovanniBarris, Corporate Trust Department; by telephone to: (212) 815-6908; or by e-mail to:geovanni.barris@bnymellon.com.     The information in this report relating to the Prudhoe Bay Unit, the calculation of royaltypayments and certain other matters has been furnished to the Trustee by BP Alaska.**Forward-Looking Statements**     Various sections of this report contain forward-looking statements (that is, statementsanticipating future events or conditions and not statements of historical fact). Words such as“anticipate,” “expect,” “believe,” “intend,” “plan” or “project,” and “should,” “would,” “could,”“potentially,” “possibly” or “may,” and other words that convey uncertainty of future events oroutcomes are intended to identify forward-looking statements. Forward-looking statements in thisreport are subject to a number of risks and uncertainties beyond the control of the Trustee. Theserisks and uncertainties include such matters as future changes in oil prices, oil productionlevels, economic activity, domestic and international political events and developments,legislation and regulation, and certain changes in expenses of the Trust.     The actual results, performance and prospects of the Trust could differ materially from thoseexpressed or implied by forward-looking statements. Descriptions of some of the risks that couldaffect the future performance of the Trust appear in the following Item 1A, “RISK FACTORS,” andelsewhere
 

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in this report. There may be additional risks of which the Trustee is unaware or whichare currently deemed immaterial.     In the light of these risks, uncertainties and assumptions, you should not rely unduly on anyforward-looking statements. Forward-looking events and outcomes discussed in this report may notoccur or may turn out differently. The Trustee undertakes no obligation to update forward-lookingstatements after the date of this report, except as required by law, and all such forward-lookingstatements 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 entitlesthe Trust to a royalty on 16.4246% of the lesser of (i) thefirst 90,000 barrels* of theaverage actual daily net production of crude oil and condensate per quarter from the workinginterest of BP Alaska as of February 28, 1989 in the Prudhoe Bay oil field located on the NorthSlope in Alaska or (ii) the average actual daily net production of crude oil and condensate perquarter from that working interest. The Prudhoe Bay field is one of four contiguous North Slope oilfields that are operated by BP Alaska and are known collectively as the “Prudhoe Bay Unit.” TheRoyalty 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 StandardOil to the Trust. Copies of the Overriding Royalty Conveyance and the Trust Conveyance are filedwith the SEC as exhibits to this report. The Overriding Royalty Conveyance and the Trust Conveyanceare referred to collectively in this report as the “Conveyance.”     The Royalty Interest is a non-operational interest in minerals. The Trust does not have theright to take oil and gas in kind, nor does it have any right to take over operations or to sharein any operating decision with respect to BP Alaska’s working interest in the Prudhoe Bay field. BPAlaska is not obligated to continue to operate any well or maintain or attempt to maintain in forceany portion of its working interest when, in its reasonable and prudent business judgment, the wellor 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 theTrustee.**Duties and Powers of the Trustee**     The duties of the Trustee are specified in the Trust Agreement and the laws of the State ofDelaware. BNY Mellon Trust of Delaware has been appointed co-trustee in order to satisfy theDelaware Statutory Trust Act’s requirement that the Trust have at least one trustee resident in, orwhich has its principal place of business in, Delaware. However, The Bank of New York Mellon aloneis able to exercise the rights and powers granted to the Trustee in the Trust Agreement. A copy of theTrust Agreement is filed with the SEC as an exhibit to this report. * The term “barrel” is a unit of measure ofpetroleum liquids equal to 42 United States gallons corrected to 60 degreesFahrenheit temperature.
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     The basic function of the Trustee is to collect income from the Royalty Interest, to pay allexpenses, charges and obligations of the Trust from the Trust’s income and assets, and to payavailable cash to Unit holders. Because of the passive nature of the Trust’s assets and therestrictions on the power of the Trustee to incur obligations, the only liabilities that the Trustnormally incurs in the conduct of its operations are the Trustee’s fees and routine administrativeexpenses, including accounting, legal and other professional fees.     The Trust Agreement grants the Trustee only the rights and powers necessary to achieve thepurposes of the Trust. The Trust Agreement prohibits the Trust from engaging in any business orcommercial activity or, with certain exceptions, any investment activity and from using any assetsof 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 orloss 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 thecompensation 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 aninterest therein only if authorized to do so by vote of the holders of 70% of the Units outstandingif the sale is to be effected on or before December 31, 2010, or holders of 60% of the Unitsoutstanding if the sale is to be effected after 2010. However, if the sale is made in order to payspecific 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 ofthe Units. Any sale of Trust properties must be for cash unless otherwise authorized by the Unitholders. The Trustee is obligated to distribute the available net proceeds of any such sale to theUnit 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 payliabilities of the Trust and to establish a reserve for the payment of liabilities without theconsent of the Unit holders under the following circumstances:     The Trustee may borrow from a lender not affiliated with the Trustee if cash on hand isnot sufficient to pay current liabilities and the Trustee has determined that it is notpractical to pay such liabilities out of funds anticipated to be available in subsequentquarters and that, without such borrowing, the Trust property is subject to the risk of lossor diminution in value. To secure payment of its borrowings on behalf of the Trust, theTrustee is authorized to encumber the Trust’s assets and to carve out and convey productionpayments. The borrowing must be on terms which (in the opinion of an investment banking firmor commercial banking firm selected by the Trustee) are commercially reasonable whencompared to other available alternatives. No distributions to Unit holders may be made untilthe borrowings by the Trust have been repaid in full.     If the Trustee is unable to borrow to pay Trust liabilities, the Trustee may sell Trustassets if it determines that the failure to pay the liabilities at a later date will becontrary to the best interest of the Unit holders and that it is not practicable to submitthe sale to a vote of the Unit holders. The sale must be made for cash at a price which (inthe opinion of an investment banking firm or commercial banking firm selected by the Trustee) is at least equal tothe fair market value of the interest sold and is made on commercially reasonable terms whencompared to other available alternatives.
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     The Trustee has the right to establish a cash reserve for the payment of materialliabilities of the Trust which may become due if it determines that it is not practical topay such liabilities out of funds anticipated to be available in subsequent quarters andthat, in the absence of a reserve, the Trust property is subject to the risk of loss ordiminution in value or the Trustee is subject to the risk of personal liability for suchliabilities.     In order for the Trustee to borrow, sell assets to pay Trust liabilities or establish areserve for Trust liabilities, the Trustee must receive an unqualified written legal opinion thatthe contemplated action will not adversely affect the classification of the Trust as a “grantortrust” for federal income tax purposes or cause the income from the Trust to be treated asunrelated business taxable income for federal income tax purposes. If the Trustee is unable toobtain the required legal opinion, it still may proceed with the borrowing or sale, or establishthe reserve, if it determines that the failure to do so will be materially detrimental to the Unitholders considered as a whole.     The Trustee maintains a $1,000,000 cash reserve to provide liquidity to the Trust during anyperiods in which the Trust does not receive a distribution from BP Alaska. See Item 7 in Part IIbelow.**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, tocorrect or supplement any provision of the Trust Agreement that may be inconsistent with any otherprovision or to make any other provision with respect to matters arising under the Trust Agreementthat does not adversely affect the Unit holders. The Trust Agreement also may be amended with theapproval of holders of a majority of the outstanding Units. However, no such amendment may alterthe relative rights of Unit holders unless approved by the affirmative vote of holders of 100% ofthe 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 otherchanges, unless approved by the affirmative vote of holders of at least 80% of the outstandingUnits and by the Trustee. The Trustee is required to consent to any amendment approved by therequisite vote of Unit holders unless the amendment affects the Trustee’s rights, duties andimmunities under the Trust Agreement. No amendment will be effective until the Trustee has receiveda ruling from the Internal Revenue Service or an opinion of counsel to the effect that suchmodification will not adversely affect the classification of the Trust as a “grantor trust” forfederal income tax purposes or cause the income from the Trust to be treated as unrelated businesstaxable 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% of theoutstanding Units vote to terminate the Trust, or (ii) after December 31, 2010 if either (a)holders of at least 60% of the outstanding Units vote to terminate the Trust or (b) the netrevenues 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 certainextraordinary events).     Upon termination of the Trust, BP Alaska will have an option to purchase the Royalty Interestat a price equal to the greater of (i) the fair market value of the Trust property as set forth inan opinion of an investment banking firm, commercial banking firm or other entity qualified to givean opinion as to the
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fair market value of the assets of the Trust, or (ii) the number ofoutstanding Units multiplied by (a) the closing price of Units on the day of termination of theTrust on the stock exchange on which the Units are listed, or (b) if the Units are not listed onany stock exchange but are traded in the over-the-counter market, the closing bid price on the dayof termination of the Trust as quoted on the NASDAQ National Market System. The purchase must befor cash unless holders of 70% of the Units outstanding (60% if the decision to terminate the Trustis made after December 31, 2010) authorize the sale for non-cash consideration and the Trustee hasreceived a ruling from the Internal Revenue Service or an opinion of counsel to the effect thatsuch 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 unrelatedbusiness taxable income for federal income tax purposes.     If BP Alaska does not exercise its option, the Trustee will sell the Trust property on termsand conditions approved by the vote of holders of 70% of the outstanding Units (60% if the sale ismade after December 31, 2010), unless the Trustee determines that it is not practicable to submitthe matter to a vote of the Unit holders and the sale is made at a price at least equal to the fairmarket 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 deemedcommercially reasonable by that firm.     The Trustee will distribute all available proceeds to the Unit holders after satisfying allexisting liabilities of the Trust and establishing adequate reserves for the payment of contingentliabilities.     Unit holders do not have the right under the Trust Agreement to seek or secure any partitionor distribution of the Royalty Interest or any other asset of the Trust or any accounting duringthe 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 holdersof a majority of the outstanding Units at a meeting called and held in accordance with the TrustAgreement. A successor trustee may be appointed by BP Alaska or, if the Trustee has been removed ata meeting of the Unit holders, the successor trustee may be appointed by the Unit holders at themeeting. Any successor trustee must be a corporation organized, doing business and authorized toexercise trust powers under the laws of the United States, any state thereof or the District ofColumbia, or a national banking association domiciled in the United States, in either case having acombined capital, surplus and undivided profits of at least $50,000,000 and subject to supervisionor examination by federal or state authorities. Unless the Trust already has a trustee that is aresident of or has a principal office in Delaware, any successor trustee must be a resident ofDelaware or have a principal office in Delaware. No resignation or removal of the Trustee willbecome 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 tothose of shareholders of a corporation. For example, there is no requirement for annual meetings ofUnit 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 asto which the Trust Agreement authorizes the Unit holders to act. Any such meeting may be called bythe Trustee in its discretion and will be called by the Trustee (i) as soon as practicable afterreceipt of a written request by BP Alaska or a written request that sets forth in reasonable detailthe action proposed to be taken at the meeting and is signed by holders of at least 25% of theoutstanding Units or (ii) when
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required by applicable laws or regulations or the New York StockExchange. The Trustee will give written notice of any meeting stating the time and place of themeeting and the matters to be acted on not more than 60 days nor fewer than 10 days before themeeting to all Unit holders of record on a date not more than 60 days before the meeting at theiraddresses shown on the records of the Trust. All meetings of Unit holders are required to be heldin Manhattan, New York City. Unit holders are entitled to cast one vote on all matters comingbefore 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 thereis no other security interest in the reserves or production revenues assigned to it. The royaltypayable to the Trust for each calendar quarter is the sum of the amounts obtained by multiplyingRoyalty Production for each day in the calendar quarter by the Per Barrel Royalty for that day. Thepayment under the Royalty Interest for any calendar quarter may not be less than zero nor more thanthe aggregate value of the total production of oil and condensate from BP Alaska’s working interestin the Prudhoe Bay Unit for the quarter, net of the State of Alaska royalty and less the value ofany applicable payments made to affiliates of BP Alaska.**Royalty Production**     The “Royalty Production” for each day in a calendar quarter is 16.4246% of the lesser of (i)the first 90,000 barrels of the actual average daily net production of crude oil and condensate forthe quarter from the Prudhoe Bay (Permo-Triassic) Reservoir and saved and allocated to the oil andgas leases owned by BP Alaska in the Prudhoe Bay field as of February 28, 1989 (the “BP WorkingInterests”), or (ii) the actual average daily net production of crude oil and condensate for thequarter from the BP Working Interests. The Royalty Production is based on oil produced from the oilrim and condensate produced from the gas cap, but not on gas production or natural gas liquidsproduction. The actual average daily net production of oil and condensate from the BP WorkingInterests 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 Texasintermediate crude oil of standard quality having a specific gravity of 40 API degrees for deliveryat Cushing, Oklahoma (“West Texas Intermediate”) quoted for that trading day by whichever of TheWall Street Journal, Reuters, or Platts Oilgram Price Report, in that order, publishes West TexasIntermediate price quotations for the trading day, or (ii) if the price of West Texas Intermediateis not published by one of those publications, the WTI Price will be the simple average of thedaily mean prices (in dollars per barrel) quoted for West Texas Intermediate by one major oilcompany, one petroleum broker and one petroleum trading company designated by BP Alaska, in eachcase unaffiliated with BP and having substantial U.S. operations, until published price quotationsare again available. If prices for West Texas Intermediate are not quoted so as to permit thecalculation of the WTI Price, the price of “West Texas Intermediate,” for the purposes ofcalculating the WTI Price will be the price of another light sweet domestic crude oil of standardquality designated by BP Alaska and approved by the Trustee, with
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appropriate allowance for transportation costs to the Gulf coast (or another appropriate location) to equilibrate its priceto the WTI Price. The WTI Price for any day which is not a trading day is the WTI Price for thepreceding trading day.**Chargeable Costs**     The “Chargeable Costs” per barrel of Royalty Production for each calendar year are fixedamounts specified in the Conveyance and do not necessarily represent BP Alaska’s actual costs ofproduction. Chargeable Costs per barrel were $12.00 during 2004, $12.25 during 2005, $12.50 during2006, $12.75 during 2007 and $13.00 during 2008. Chargeable Costs for 2009 and subsequent years areshown in the following table:             **Calendar** **Chargeable Costs** **Calendar** **Chargeable Costs****year** **per barrel** **year** **per barrel**2009 $13.25   2015  $17.00 2010  14.50   2016   17.10 2011  16.60   2017   17.20 2012  16.70   2018   20.00 2013  16.80   2019   23.75 2014  16.90   2020   26.50      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 publishedfor the most recently past February, May, August or November to 121.1 (the Consumer Price Index forJanuary 1989). The “Consumer Price Index” is the U.S. Consumer Price Index, all items and all urbanconsumers, 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 orcorrections. If the average WTI Price for any calendar quarter falls to $18.00 or less, the CostAdjustment Factor for that quarter will be the Cost Adjustment Factor for the immediately precedingquarter. If the average WTI Price returns to more than $18.00 for a later quarter, adjustments tothe Cost Adjustment Factor resume, but with an adjustment to the formula that excludes changes inthe Consumer Price Index during the period that adjustments to the Cost Adjustment Factor weresuspended.**Production Taxes**     “Production Taxes” are the sum of any severance taxes, excise taxes (including windfall profittax, if any), sales taxes, value added taxes or other similar or direct taxes imposed upon thereserves or production, delivery or sale of Royalty Production, computed at defined statutoryrates.     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% of thegross value of oil at the point of production (the wellhead or field value) and which, as requiredby the Conveyance, was applied for the purpose of determining the Royalty Interest without regardto the “economic limit factor” (a formula designed to result in low tax rates for smaller lowproductive fields and higher tax rates for larger highly productive fields), and (ii) a surchargeof $0.03 per barrel of Royalty Production. The Conveyance provides that, in the case of taxes basedupon wellhead or field value, the WTI Price less the product of $4.50 multiplied by the CostAdjustment Factor is deemed to be the wellhead or field value.
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     Alaska adopted a new oil and gas production tax on August 20, 2006 (Chapter 2, Third SpecialSession Laws of Alaska 2006) (the “2006 Tax”) which amended the Alaska oil and gas production taxstatutes, AS 43.55.10 et seq. (the “Production Tax Statutes”) and replaced the Old Tax. Under the2006 Tax, producers are taxed on the “production tax value of taxable oil” (gross value at thepoint 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 inAlaska (“Lease Expenditures”) 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 2006 Tax was equal to 0.25% times the amount by which the simpleaverage for each calendar month of the daily production tax values per barrel of the oil producedduring the month exceeded $40 per barrel. In addition, the 2006 Tax increased the surcharge on oilproduced from leases or properties in Alaska from $0.03 to $0.04 per barrel.     On December 20, 2007, a bill (Chapter 1, Second Special Session Laws of Alaska 2007) (the“2007 Tax”) took effect and further amended the Production Tax Statutes in certain respects. The2007 Tax changed the basic tax rate from 22.5% to 25% and increased the progressivity rate. If theproducer’s average monthly production tax value per barrel is greater than $30 but not more than$92.50, the new progressivity tax rate is 0.4% times the amount by which the average monthlyproduction tax value exceeds $30 per barrel. If the producer’s average monthly production tax valueper barrel is greater than $92.50, the progressivity tax rate is the sum of 25% and the product of0.1% multiplied by the difference between the average monthly production tax value per barrel and$92.50, except that the sum may not exceed 50%.     In order to resolve uncertainties in the interpretation of the Conveyance resulting fromadoption of the 2006 Tax, in October 2006 the Trustee entered into a letter agreement with BPAlaska (the “2006 Letter Agreement”), a copy of which is incorporated by reference as Exhibit 4.5to this report. The 2006 Letter Agreement sets forth principles agreed to by BP Alaska and theTrustee to resolve how the amount of tax chargeable against the Royalty Interest was to bedetermined under the Conveyance and the extent to which the retroactivity of the tax legislationwas to be recognized for purposes of the Conveyance (the “Consensus Principles”). In December 2007,BP Alaska notified the Trustee that the adoption of the 2007 Tax made it necessary to modify theConsensus Principles to give effect to the new tax rates. After determining that the proposedchanges to the Consensus Principles were consistent with the changes in tax rates effected by the2007 Tax, on January 11, 2008 the Trustee executed a letter agreement datedDecember 21, 2007 with BP Alaska (the “2008 Letter Agreement”) which supplements and amendsthe 2006 Letter Agreement and which is incorporated by reference as Exhibit 4.6 to this report.     ***Determination of Production Taxes***     The following paragraphs describe how the Consensus Principles provide for the amount ofProduction Taxes (other than the $0.04 per barrel surcharge) to be determined under the 2006 Tax(from August 20, 2006 through December 19, 2007) and under the 2007 Tax (from December 20, 2007 andthereafter): (a) The production tax value per barrel of oil for each day is determined bytaking the WTI Price for that day and subtracting the product of the amount ofthe Chargeable Costs then in effect multiplied by the applicable CostAdjustment Factor.
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 (b) The tax rate for the “progressivity” portion of the tax equals:   2006 Tax 2007 Tax   (i) zero, if the simpleaverage of the dailytaxable values per barrelunder (a) above for acalendar month is notgreater than $40 perbarrel; or (i) zero, if the simple average ofthe daily taxable values per barrelunder (a) above for a calendar monthis not greater than $30 per barrel;   (ii) 0.25% times the amountby which the simple averagefor each calendar month ofthe daily production taxvalues per barrel of oilunder (a) above, exceeds$40 per barrel. (ii) 0.4% times the amount by whichthe simple average of the taxablevalues per barrel under (a) abovefor a calendar month exceeds $30 perbarrel if that average is notgreater than $92.50 per barrel; or     (iii) the sum of 25% plus 0.1% timesthe amount by which the simpleaverage of the taxable values perbarrel under (a) above for acalendar month exceeds $92.50,except that such sum may not exceed50%. (c) The amount of Production Tax chargeable against the Royalty Interest equalsthe taxable value per barrel under (a) above times the Royalty Production underthe Conveyance, times a rate equal to the sum of the “progressivity” ratedetermined under (b) above plus the following percentage:   2006 Tax 2007 Tax   22.5% 25%     ***Retroactivity of Tax***     Although both the 2006 Tax and the 2007 Tax are retroactive (to April 1, 2006, in the case ofthe 2006 Tax; to July 1, 2007, in the case of the 2007 Tax), in the Consensus Principles theparties agreed that the 2006 Tax and 2007 Tax would not be applied retroactively to payments by BPAlaska with respect to the Royalty Interest. Production Taxes charged against the Royalty Interestwere the amount of Old Tax as calculated under the Conveyance for oil production during the periodfrom April 1 to August 19, 2006, inclusive. For oil produced on August 20, 2006 through December19, 2007, the Production Taxes charged against the Royalty Interest were the amount of 2006 Tax,determined as described above, for that production, and for oil produced on December 20, 2007 andthereafter the Production Taxes charged against the Royalty Interest are the amount of 2007 Tax,determined as described above.
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     ***Use of Inflation Adjusted Chargeable Costs under Consensus Principles***     The 2006 Letter Agreement contains a discussion of the rationale for using inflation adjustedChargeable Costs as a proxy for BP Alaska’s actual Lease Expenditures for purposes of determiningProduction Taxes chargeable against the Royalty Interest. The 2006 Letter Agreement explains thatunder the 2006 Tax BP Alaska is required to use estimates of Lease Expenditures for purposes of itsmonthly reporting to the State of Alaska, and that actual Lease Expenditures are determined andreconciled to monthly estimates up to three months after the close of each fiscal year. The use ofBP Alaska’s estimated Lease Expenditures for purposes of calculating the Production Taxes appliedto quarterly payments of the Royalty Interest could require regular adjustments to future royaltypayments to compensate for over or under charges of Production Taxes to past royalty payments onceactual Lease Expenditures were determined. These adjustments could create unfair benefits forcertain Unit holders and unfair detriment to others. BP Alaska stated that inflation adjustedChargeable Costs were expected to provide a reasonable, although not an exact, approximation of BPAlaska’s Leasehold Expenditures and provide certainty to investors in the Trust Units. BP Alaskacautioned, however, that to the extent actual Lease Expenditures for a particular year are higherthan adjusted Chargeable Costs for the year, the Trust Units may bear Production Taxes at a higherrate than the rate of tax applicable to BP Alaska’s production for the year; conversely, if BPAlaska’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 rateof tax applicable to BP Alaska’s production.     In addition to changes in the rates of tax applicable to oil and gas production introduced bythe 2007 Tax, the legislation authorizes the Alaska Department of Revenue (“DOR”) to interpret andapply the amendments to the Production Tax Statutes. The 2007 Tax allows DOR to limit deductibletransportation costs for transportation by a regulated pipeline to something less than the tariffactually paid. Other amendments allow DOR to exclude by regulation certain categories of otherwisedeductible lease expenditures, or a fixed percentage of them, from being deductible in determiningthe production tax value of taxable oil. In the 2008 Letter Agreement, BP Alaska indicated that,depending on what the new regulations provide, it may wish to amend the Consensus Principles sothat something less than the full amount of Chargeable Costs is to be deducted under the Conveyancein determining the taxable value per barrel. Any such amendment would require the consent of theTrustee. If any such amendment should be proposed, the Trustee will evaluate the proposal todetermine whether such amendment is consistent with the Conveyance and the interests of the Unitholders of the Trust and will make its decision accordingly.
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**Per Barrel Royalty Calculations**     The following table shows how the above-described factors interacted during the past fiveyears to produce the average Per Barrel Royalty paid during the calendar years indicated. Royaltyrevenues are generally received on the fifteenth day of the month following the end of the calendarquarter in which the related Royalty Production occurred. Revenues and expenses presented in thestatement of cash earnings and distributions presented in Part II, Item 8 below are recorded on amodified cash basis and, as a result, royalty revenues and distributions shown in such statementsfor any calendar year are attributable to BP Alaska’s operations during the twelve-month periodended September 30 of that year.                                   **Cost** **Adjusted**     **Average Per**  **Average** **Chargeable** **Adjustment** **Chargeable** **Production** **Barrel**  **WTI Price** **Costs** **Factor** **Costs** **Taxes(1)** **Royalty**                         **Calendar 2004:**                        4th Qtr 2003 $31.23  $11.75   1.421  $16.69  $3.76  $10.78 1st Qtr 2004  35.18   12.00   1.434   17.20   4.34   13.64 2nd Qtr 2004  38.31   12.00   1.456   17.47   4.79   16.05 3rd Qtr 2004  43.78   12.00   1.459   17.51   5.61   20.66                          **Calendar 2005:**                        4th Qtr 2004  48.35   12.00   1.471   17.65   6.29   24.41 1st Qtr 2005  49.70   12.25   1.477   18.09   6.49   25.12 2nd Qtr 2005  53.09   12.25   1.497   18.34   6.98   27.77 3rd Qtr 2005  63.03   12.25   1.512   18.53   8.46   36.04                          **Calendar 2006:**                        4th Qtr 2005  60.01   12.25   1.521   18.63   8.01   33.37 1st Qtr 2006  63.36   12.50   1.530   19.13   8.50   35.73 2nd Qtr 2006  70.53   12.50   1.559   19.49   9.56   41.48 3rd Qtr 2006  70.64   12.50   1.570   19.63   10.68   40.34                          **Calendar 2007:**                        4th Qtr 2006  60.17   12.50   1.552   19.39   9.31   31.46 1st Qtr 2007  58.17   12.75   1.567   19.98   8.66   29.54 2nd Qtr 2007  65.00   12.75   1.601   20.42   10.59   34.00 3rd Qtr 2007  75.29   12.75   1.601   20.42   14.45   40.42                          **Calendar 2008:**                        4th Qtr 2007  90.93   12.75   1.618   20.63   22.29   48.01 1st Qtr 2008  97.78   13.00   1.630   21.19   33.58   43.01 2nd Qtr 2008  124.34   13.00   1.668   21.68   52.37   50.29 3rd Qtr 2008  118.69   13.00   1.687   21.93   48.18   48.58  (1) Production Taxes for the third quarter of 2006 and subsequent quarters reflect the effect ofthe 2006 amendment of the Alaska oil and gas Production Tax Statutes. Production taxes for thefirst quarter of 2008 and subsequent periods reflect the application of the 2007 amendment ofthe Production Tax Statutes. (2) Dollar amounts in the table have been rounded to two decimal places for presentation and donot reflect the precision of the actual calculations.
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**THE UNITS****Units**     Each Unit represents an equal undivided share of beneficial interest in the Trust. The Unitsdo not represent an interest in or an obligation of BP Alaska, Standard Oil or any of theirrespective affiliates. Units are evidenced by transferable certificates issued by the Trustee. EachUnit entitles its holder to the same rights as the holder of any other Unit. The Trust has no otherauthorized 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’sRoyalty Interest on the fifteenth day following the end of each calendar quarter or, if thefifteenth 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 theextent possible, then distributes the excess, if any, of the cash received by the Trust over theTrust’s expenses, net of any additions to or subtractions from the cash reserve established for thepayment of estimated liabilities (the “Quarterly Distribution”), to the persons in whose names theUnits 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 onthe fifth day after the Trustee’s receipt of the amount paid by BP Alaska. Cash balances held bythe Trustee for distribution to Unit holders are required to be invested in United Statesgovernment 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 thedistribution to Unit holders are not available, in repurchase agreements secured by GovernmentObligations with banks having capital, surplus and undivided profits of $100,000,000 or more (whichmay include The Bank of New York Mellon). If time does not permit the Trustee to invest collectedfunds in Government Obligations or repurchase agreements, the Trustee may invest funds overnight ina time deposit with a bank meeting the foregoing capital requirement (including The Bank of NewYork Mellon).**Reports to Unit Holders**     After the end of each calendar year, the Trustee mails a report to the persons who held Unitsof record during the year containing information to enable them to make the calculations necessaryfor federal and Alaska income tax purposes, including the calculation of any depletion or otherdeduction which may be available to them for the calendar year. In addition, after the end of eachcalendar year the Trustee mails Unit holders an annual report containing a copy of this Form 10-Kand 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 byDelaware law, entitled to the same limitation of personal liability extended to stockholders ofprivate corporations for profit under Delaware law.**Possible Divestiture of Units**     The Trust Agreement imposes no restrictions on nationality or other status of the personseligible to hold Units. However, it provides that if at any time the Trust or the Trustee is nameda party in any
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judicial or administrative proceeding seeking the cancellation or forfeiture of anyproperty in which the Trust has an interest because of the nationality, or any other status, of anyone or more Unit holders, the Trustee may require each holder whose nationality or other status isan issue in the proceeding to dispose of his Units to a party not of the nationality or otherstatus at issue in the proceeding. If any holder fails to dispose of his Units within 30 days afterreceipt of notice from the Trustee to do so, the Trustee will redeem any Units not so transferredwithin 90 days after the end of the 30-day period specified in the notice for a cash price equal tothe 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 thepurchase of Units from an ineligible holder by the Trustee would result in a non-exempt “prohibitedtransaction” under the Employee Retirement Income Security Act of 1970, or under the InternalRevenue Code of 1986, the Units subject to the Trustee’s right of redemption will be purchased byBP 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 tothe Trust additional royalty interests meeting certain conditions and, upon satisfaction of variousother conditions, the Trust may issue up to an additional 18,600,000 Units. BP Alaska has notconveyed any additional royalty interests to the Trust, and the Trust has not issued any additionalUnits.**THE BP SUPPORT AGREEMENT**     BP agreed to provide financial support to BP Alaska in meeting its payment obligations to theTrust in a Support Agreement dated February 28, 1989 among BP, BP Alaska, Standard Oil and theTrust (the “Support Agreement”). Within 30 days after BP receives notice from the Trustee that theroyalty payable with respect to the Royalty Interest or any other amount payable by BP Alaska orStandard Oil has not been paid to the Trustee, BP will cause BP Alaska and Standard Oil to satisfytheir respective payment obligations to the Trust and the Trustee under the Trust Agreement and theConveyance, including contributing to BP Alaska the funds necessary to make such payments. BP isrequired 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 toinstitute 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 SupportAgreement without the prior written consent of the Trustee, except that BP can arrange for itsobligations to be performed by any its affiliates so long as BP remains responsible for ensuringthat 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’spayment obligations with respect to the Royalty Interest and under the Trust Agreement and theConveyance are performed.     BP will be released from its obligation under the Support Agreement upon the sale or transferof all or substantially all of BP Alaska’s working interest in the Prudhoe Bay Unit if thetransferee 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 theTrustee and the transferee must be an entity having a rating of its unsecured, unsupportedlong-term debt of at least A3 from Moody’s Investors Service, Inc., a rating of at least A- fromStandard & Poor’s, or an equivalent rating
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from at least one nationally-recognized statisticalrating organization (after giving effect to the sale or transfer and the assumption of all of BPAlaska’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, aswell as several contiguous oil fields, the Prudhoe Bay Unit was established to optimize fielddevelopment. Other owners of these fields include affiliates of Exxon Mobil Corporation,ConocoPhillips and ChevronTexaco Corporation. The Trust’s Royalty Interest pertains only toproduction from the BP Working Interests in the Prudhoe Bay field and does not include productionfrom 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 aregoverned by an agreement dated April 1, 1977 among the State of Alaska and the working interestowners establishing the Prudhoe Bay Unit (the “Prudhoe Bay Unit Agreement”) and an agreement datedApril 1, 1977 among the working interest owners governing Prudhoe Bay Unit operations (the “PrudhoeBay Unit Operating Agreement”).     The Prudhoe Bay Unit Operating Agreement specifies the allocation of production and costs tothe working interest owners. It also defines operator responsibilities and voting requirements andis unusual in its establishment of separate participating areas for the gas cap and oil rim. SinceJuly 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, 2008 is shownin the following table:           **Oil rim**  **Gas cap**          BP Alaska   26.36%(a)  26.36%(b)Exxon Mobil   36.40   36.40 ConocoPhillips   36.08   36.08 ChevronTexaco   1.16   1.16        Total   100.00%  100.00%        (a) The Trust’s share of oil production is computed based on BP Alaska’s ownership interestin the oil rim participating area of 50.68% as of February 28, 1989. Subsequent decreasesin BP Alaska’s participation in oil rim ownership do not affect calculation of RoyaltyProduction from the BP Working Interests and have not decreased the Trust’s RoyaltyInterest. (b) The Trust’s share of condensate production is computed based on BP Alaska’s ownershipinterest in the gas cap participating area of 13.84% as of February 28, 1989. Subsequentincreases in BP Alaska’s gas cap ownership do not affect calculation of Royalty Productionfrom the BP Working Interests and have not increased the Trust’s Royalty Interest.     If BP Alaska fails to pay any costs and expenses chargeable to BP Alaska under the Prudhoe BayUnit Operating Agreement and the production of oil and condensate is insufficient to pay such costsand expenses, the Royalty Interest is chargeable with a pro rata portion of such costs and expensesand is subject to the enforcement against it of liens granted to the operators of the Prudhoe BayUnit. However,
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in the Conveyance BP Alaska agreed to pay all costs and expenses chargeable to itand to ensure that no such costs and expenses will be chargeable against the Royalty Interest. TheTrust is not liable for any loss or liability incurred by BP Alaska or others attributable to BPAlaska’s working interest in the Prudhoe Bay Unit or to the oil produced from it and BP Alaska hasagreed 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 BayUnit Operating Agreement and any leases or conveyances with respect to the BP Working Interests inthe exercise of its reasonable and prudent business judgment without liability to the Trust. BPAlaska also has the right to sell or assign all or any part of the BP Working Interests, so long asthe sale or assignment is expressly made subject to the Royalty Interest and the terms andprovisions of the Conveyance.**The Prudhoe Bay Field**     The Prudhoe Bay field is located on the North Slope of Alaska, 250 miles north of the ArcticCircle and 650 miles north of Anchorage. The Prudhoe Bay field extends approximately 12 miles by 27miles and contains nearly 150,000 productive acres. The Prudhoe Bay field, which was discovered in1968 by BP and others, has been in production since 1977 and is the largest producing oil field inNorth America. As of December 31, 2008, approximately 11.1 billion barrels of oil and condensatehad been produced from the Prudhoe Bay field.**Field Geology**     The principal hydrocarbon accumulations at Prudhoe Bay are in the Ivishak sandstone of theSadlerochit Group at a depth of approximately 8,700 feet below sea level. The Ivishak is overlainby four minor reservoirs of varying extent which are designated the Put River, Eileen, Sag Riverand Shublik (“PESS”) formations. Underlying the Sadlerochit Group are the oil-bearing Lisburne andEndicott formations. The net production allocated to the Royalty Interest pertains only to theIvishak and PESS formations, collectively known as the Prudhoe Bay (Permo-Triassic) Reservoir, anddoes not pertain to the Lisburne and Endicott formations.     The Ivishak sandstone was deposited, commencing some 250 million years ago, during the Permianand Triassic geologic periods. The sediments in the Ivishak are composed of sandstone, conglomerateand shale which were deposited by a massive braided river and delta system that flowed from anancient mountain system to the north. Oil was trapped in the Ivishak by a combination of structuraland stratigraphic trapping mechanisms.     Gross reservoir thickness is 550 feet, with a maximum oil column thickness of 425 feet. Theoriginal oil column is bounded on the top by a gas-oil contact, originally at 8,575 feet below sealevel across the main field, and on the bottom by an oil-water contact at approximately 9,000 feetbelow sea level. A layer of heavy oil and tar overlays the oil-water contact in the main field andhas an average thickness of around 40 feet.**Oil Characteristics**     The oil produced from the Prudhoe Bay (Permo-Triassic) Reservoir is a medium grade, low sulfurcrude 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.
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     The Royalty Interest is based upon oil produced from the oil rim and condensate produced fromthe gas cap, but not upon gas production (which is currently uneconomic on a large scale) ornatural gas liquids production stripped from gas produced.**Historical Production**     Production from the Prudhoe Bay field began on June 19, 1977, with the completion of theTrans-Alaska Pipeline System (“TAPS”). As of December 31, 2008 there were about 1,128 activeproducing oil wells, 34 gas reinjection wells, 88 water injection wells and 133 water and misciblegas injection wells in the Prudhoe Bay field. Production from the Prudhoe Bay field reached a peakin 1988 and has declined steadily since then. The average well production rate was about 317barrels per day in 2004, 293 barrels per day in 2005, 223 barrels per day in 2006, 232 barrels perday in 2007 and 232 barrels per day in 2008. There was a temporary impact on production from theeast side of the Prudhoe Bay Unit as a result of the August 2006 partial shutdown, as discussed inthe last paragraph under the heading “Collection and Transportation of Prudhoe Bay Oil,” below     BP Alaska’s share of the hydrocarbon liquids production from the Prudhoe Bay field includesoil, condensate and natural gas liquids. Using the production allocation procedures from thePrudhoe Bay Unit Operating Agreement, the Prudhoe Bay field’s total production and the net share ofoil and condensate (net of State of Alaska royalty) allocated to the BP Working Interests have beenas follows during the past five years:                   **Oil** **Condensate**      **Net to BP**     **Net to BP**      **Working**     **Working****Calendar** **Total field** **Interests** **Total field** **Interests****year** **(thousand barrels per day)**2004  243.4   107.9   109.0   13.2 2005  228.9   101.5   96.4   11.7 2006  173.9   77.1   76.7   9.3 2007 (a)  184.1   81.6   77.9   9.4 2008  192.7   85.4   69.4   8.4  (a) 2007 production figures reported in the Trust’s Annual Report on Form 10-K for the yearended December 31, 2007 have been revised to reflect actual production for the year.**Collection and Transportation of Prudhoe Bay Oil**     Raw crude oil produced from individual production wells located at well pads is diverted toflowlines (pipelines). The flowlines transport the raw crude oil to one of six separationfacilities (three on the western side of the Prudhoe Bay Unit and three on the eastern side) wherethe water and natural gas mixed with the raw crude are removed. The stabilized crude is then sentfrom the separation facilities through two 34-inch diameter transit lines, one from each half ofthe 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 andpumps 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 sevendays to make the trip from the Prudhoe Bay Unit to Valdez. TAPS has a capacity of approximately 1.4million barrels of oil per day.
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     On August 7, 2006, BP announced that BP Alaska had begun a shutdown of the Prudhoe Bay Unitfollowing the discovery of unexpectedly severe corrosion and a small spill from the oil transitline on the eastern side of the field. The decision followed the receipt several days earlier ofdata from a “smart pig”† run completed in late July. Analysis of the data revealed 16anomalies 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 criteriafor continued operation and a leak and small spill estimated at four to five barrels. BP hadpreviously announced plans to replace a three-mile segment of transit line on the western side ofthe Prudhoe Bay field following inspections conducted after a large spill caused by corrosiondiscovered in March 2006.     BP subsequently determined to shut down only the eastern side of the Prudhoe Bay Unit andcontinue production from the western side of the Unit. The partial shutdown of the field reducedaverage daily production to approximately half of normal output. On September 22, 2006, BPannounced that it had received clearance from the U.S. Department of Transportation (“DOT”) torestart production in the eastern half of the Prudhoe Bay Unit. In December 2008 BP completed thereplacement of approximately 16 miles of oil transit lines. BP Alaskahas implemented new integrity management and corrosion monitoringpractices that supplement or replace the practicesthat existed in 2006. BP Alaska’s integrity management practicesmeet the requirement of 49 CFR 195.452 for pipeline integritymanagement in high consequence areas.**Reservoir Management**     The Prudhoe Bay field is a complex, combination-drive reservoir, with widely varying reservoirproperties. Reservoir management involves directing field activities and projects to maximize theeconomic 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 gasflooding. Separate yet integrated reservoir management strategies have been developed for the areasaffected by each of these recovery processes.**Reserve Estimates**     Estimates of proved reserves are inherently imprecise and subjective and are revised over timeas additional data become available. Such revisions often may be substantial. BP Alaska’s reserveestimates and production assumptions and projections are predicated upon a reasonable estimate ofthe allocation of hydrocarbon liquids between oil and condensate according to the procedures of thePrudhoe Bay Unit Operating Agreement. Oil and condensate are physically produced in a commingledstream of hydrocarbon liquids. The allocation of hydrocarbon liquids between the oil and condensatefrom the Prudhoe Bay field is a theoretical calculation performed in accordance with proceduresspecified in the Prudhoe Bay Unit Operating Agreement. Due to the differences in percentagesbetween oil and condensate, the overall share of oil and condensate production allocated to the BPWorking Interests will vary over time according to the proportions of hydrocarbon liquid being allocated ascondensate or as oil. Under the terms of an Issues Resolution Agreement entered into by the PrudhoeBay Unit owners in October 1990, the allocation procedures have been adjusted to generally allocatecondensate in a manner which approximates the anticipated decline in the production of oil until anagreed original condensate reserve of 1,175 million barrels has been allocated to the workinginterest owners. † An electronic device including magnetic fluxleakage and ultrasonic thickness testing systems that is propelled through apipeline to inspect the pipeline wall.
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     The reserves attributable to the Trust’s Royalty Interest constitute only a part of theoverall reserves allocated to the BP Working Interests. BP Alaska has estimated that the netremaining proved reserves attributable to the Trust as of December 31, 2008 were 54.954 millionbarrels of oil and condensate, of which 46.096 million barrels are proved developed reserves and8.858 million barrels are proved undeveloped reserves. Using procedures specified in FinancialAccounting Standards Board Statement of Financial Accounting Standards No. 69, BP Alaska calculatedthat as of December 31, 2008 production of oil and condensate from the proved reserves allocated tothe Trust’s Royalty Interest will result in estimated future net revenues to the Trust of $632.47million, with a present value of $418.57 million. (See Item 7 in Part II below for informationconcerning adoption by the SEC of revisions to its oil and gas reporting disclosures.) BP Alaska’sestimates of proved reserves and the estimated future net revenues from the Prudhoe Bay Unit havebeen reviewed by Miller and Lents, Ltd., independent oil and gas consultants, as set forth in theirreport 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 requireddowntime, BP Alaska’s net production of oil and condensate from proved reserves was less than90,000 barrels per day on an annual basis in 2008. BP Alaska anticipates that its average netproduction of oil and condensate from proved reserves will be below 90,000 barrels per day on anannual average basis in 2009 and all future years. The occurrence of major gas sales couldaccelerate the decline in net production, due to the consequent decline in reservoir pressure. SeeItem 1A, “RISK FACTORS.” Based on the WTI Price of $44.60 per barrel on December 31, 2008, currentProduction Taxes, and the Chargeable Costs adjusted as prescribed by the Overriding RoyaltyConveyance, it is estimated that royalty payments to the Trust will continue through the year 2020.BP Alaska expects continued economic production from the Prudhoe Bay field at a declining ratethrough 2049; however, for the economic conditions and production forecast as of December 31, 2008the Per Barrel Royalty will be zero following the year 2020.     There is no precise method of forecasting the allocation of reserve volumes between BP Alaskaand the Trust. The Royalty Interest is not a working interest and the Trust is not entitled toreceive any specific volume of reserves from the BP Working Interests. Rather, reserve volumesattributable to the Trust at any given date are estimated by allocating to the Trust its share ofestimated future production from the BP Working Interests based on WTI Prices and other economicparameters in effect on the date of the evaluation.     The following table shows the net remaining proved reserves of oil and condensate allocated tothe BP Working Interests, the net proved reserves allocated to the Trust, and the WTI Prices on thedates indicated:               **Net Proved Reserves**    **BP Working**     **WTI Price****December 31** **Interests (a)** **Trust (b)** **per barrel**  **(million barrels)**    2004  941.4   77.4  $43.46 2005  1,043.0   85.3   61.04 2006  912.1   81.1   61.06 2007  915.1   97.8   96.01 2008  791.4   55.0   44.60 
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 (a) Includes proved undeveloped reserves of 115.4 million barrels at December 31, 2004,96.0 million barrels at December 31, 2005, 84.2 million barrels at December 31, 2006, 68.7million barrels at December 31, 2007 and 63.6 million barrels at December 31, 2008. (b) Includes proved undeveloped reserves of 9.1 million barrels at December 31, 2004, 12.3million barrels at December 31, 2005, 12.1 million barrels at December 31, 2006, 10.9million barrels at December 31, 2007 and 8.9 million barrels at December 31, 2008.     The reserve volumes attributable to the Trust are estimated using an allocation of reservevolumes based on estimated future production and the current WTI Price, and assume no futuremovement in the Consumer Price Index and no changes to the procedure for calculating ProductionTaxes. The estimated reserve volumes attributable to the Trust will vary if different estimates ofproduction, prices and other factors are used. Even if expected reservoir performance does notchange, the estimated reserves, economic life, and future revenues attributable to the Trust maychange significantly in the future. This may result from changes in the WTI Price or from changesin other prescribed variables utilized in calculations defined by the Overriding RoyaltyConveyance. See Note 11 (unaudited) of the Notes to Financial Statements in Item 8.     BP Alaska is under no obligation to make investments in development projects which would addadditional non-proved resources to proved reserves and cannot make such investments without theconcurrence of the Prudhoe Bay Unit working interest owners. The Prudhoe Bay Unit working interestowners regularly assess the technical and economic attractiveness of implementing projects toincrease Prudhoe Bay Unit proved reserves. See Item 1A, “RISK FACTORS,” below.     In the event of changes in BP Alaska’s current assumptions, oil and condensate recoveries maybe reduced from the current estimates, unless recovery projects other than those included in thecurrent estimates are implemented.
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**INDEPENDENT OIL AND GAS CONSULTANTS’ REPORT**Miller and Lents, Ltd.international oil and gas consultantsfounded 1948February 12, 2009The Bank of New York Mellon