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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, 2004 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  DELAWARE
    
    13-6943724State or other jurisdiction
    
    (I.R.S. Employer Identification No.)of incorporation or organization)THE BANK OF NEW YORK, TRUSTEE101 BARCLAY STREETNEW YORK, NEW YORK
    
    10286(Address of principal executive offices)
    
    (Zip Code)
 Registrants telephone number, including area code: (212) 815-2492 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class
    
    Name of Each Exchange on Which RegisteredUNITS OF BENEFICIAL INTEREST
    
    NEW YORK STOCK EXCHANGE
 Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant: (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes 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 an accelerated filer (as defined in Exchange
Act Rule 12b-2). Yes þ No o 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, 2004 (the last business day
of the registrants most recently completed second fiscal quarter) was approximately $696,998,000. As of March 30, 2005, 21,400,000 Units of Beneficial Interest were outstanding. DOCUMENTS INCORPORATED BY REFERENCE None




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TABLE OF CONTENTS PART I
    
    
    1ITEM
1. BUSINESS
    
    
    1INTRODUCTION
    
    
    1THE TRUST
    
    
    2THE ROYALTY INTEREST
    
    
    6THE UNITS
    
    
    11THE BP SUPPORT AGREEMENT
    
    
    13THE PRUDHOE BAY UNIT
    
    
    14INDEPENDENT OIL AND GAS CONSULTANTS REPORT
    
    
    19INDUSTRY CONDITIONS AND REGULATIONS
    
    
    24CERTAIN TAX CONSIDERATIONS
    
    
    24ITEM
2.PROPERTIES
    
    
    26ITEM
3.LEGAL PROCEEDINGS
    
    
    26ITEM
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
    
    
    26PART II
    
    
    27ITEM
5. MARKET FOR THE UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS
    
    
    27ITEM
6. SELECTED FINANCIAL DATA
    
    
    27ITEM
7. TRUSTEES DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
    
    
    28ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
    
    
    29ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
    
    
    31ITEM
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
    
    
    43ITEM
9A. CONTROLS AND PROCEDURES
    
    
    43ITEM
9B. OTHER INFORMATION
    
    
    46PART III
    
    
    46ITEM
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
    
    
    46ITEM
11. EXECUTIVE COMPENSATION
    
    
    46ITEM
12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
    
    
    46ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
    
    
    47ITEM
14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
    
    
    47ITEM
15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES
    
    
    47SIGNATURES
    
    
    49Exhibit 31 CertificationExhibit 32 Certification
  i




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PART I 
 ITEM 1. BUSINESS 
 INTRODUCTION BP Prudhoe Bay Royalty Trust (the Trust), a grantor trust, was created as a Delaware
business trust pursuant to the BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 (the
Trust Agreement) among The Standard Oil Company (Standard Oil), BP Exploration (Alaska) Inc.
(the Company), The Bank of New York, as trustee (the Trustee), and F. James Hutchinson,
co-trustee (The Bank of New York (Delaware), successor co-trustee). The Trustees corporate trust
offices are located at 101 Barclay Street, New York, New York 10286 and its telephone number is
(212) 815-2492. The Company and Standard Oil are wholly owned subsidiaries of BP p.l.c. (BP). Upon creation of the Trust, the Company conveyed to Standard Oil, and Standard Oil, in turn,
conveyed to the Trust an overriding royalty interest (the Royalty Interest), which entitles the
Trust to a royalty on 16.4246 percent of the first 90,000 Barrels1 of the average actual
daily net production of oil and condensate per quarter from the working interest of the Company as
of February 28, 1989 in the Prudhoe Bay Unit located on the North Slope in Alaska (see THE PRUDHOE
BAY UNIT below). The Royalty Interest is free of any exploration and development expenditures. The only assets of the Trust are the Royalty Interest assigned to the Trust and cash or cash
equivalents held by the Trustee from time to time as reserves or for distribution (the Trust
Estate). The Trust is a passive entity, and the Trustee has been given only such powers as are
necessary for the collection and distribution of revenues from the Royalty Interest and the payment
of Trust liabilities and expenses. The beneficial interest in the Trust is divided into equal
undivided units (the Units). The Units are not an interest in or an obligation of the Company,
Standard Oil or BP. The Delaware Trust Act, under which the Trust was formed, entitles holders of
the Units to the same limitation of personal liability as stockholders of a Delaware corporation. The Company shares control of the operation of the Prudhoe Bay Unit with other working
interest owners. The operations of the Company and the other working interest owners are governed
by an agreement dated April 1, 1977 among the State of Alaska and such 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 Company has no obligation to continue production from the Prudhoe
Bay Unit or to maintain production at any level and may interrupt or discontinue production at any
time. 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 Prudhoe Bay Unit
which is covered by insurance, the Company has no obligation to use insurance proceeds to repair
such damage and may elect to retain such proceeds and close damaged areas to production. The Trustee has no responsibility for the operation of the Prudhoe Bay Unit or authority over
the Company, Standard Oil or BP. The information in this report relating to the Prudhoe Bay Unit,
the   *
    
    As used in the overriding royalty conveyance
and this report, (a) the term Barrel is a unit of measure equal
to 42 United States gallons corrected to 60 degrees Fahrenheit temperature and
with deductions for sediment and water content, and (b) the term Stock
Tank Barrel or STB refers to a Barrel of stabilized oil or
condensate at a temperature of 60 degrees Fahrenheit and sea-level atmospheric
pressure (14.7 pounds per square inch absolute).




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calculation of the royalty payments and certain other matters has been furnished to the
Trustee by the Company. The Trust electronically files annual reports on Form 10-K, quarterly reports on Form 10-Q
and, when certain events require them, current reports on Form 8-K with the Securities and Exchange
Commission (SEC). The public may read and copy any materials filed by the Trust with the SEC at
the SECs Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may
obtain information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and
information statements, and other information regarding issuers (including the Trust) that file
electronically with the SEC. The address of the SECs web site is http://www.sec.gov. The Trust does not have an Internet web site from which information concerning the Trust may
be obtained; however the Trust will make available free of charge upon request paper or electronic
copies of its reports on Form 10-K, Form 10-Q and Form 8-K, and amendments to those reports, as
soon as reasonably practicable after the Trust electronically files such material with the SEC.
Requests for copies of reports should be made, if by mail, to: The Bank of New York, 101 Barclay
Street, New York, NY 10286, Attention: Mr. Remo Reale, Corporate Trust Department; if by telephone,
to: (212) 815-2492; and, if by e-mail, to: rreale@bankofny.com. See THE UNITS  Reports to Unit
Holders below for information concerning reports provided to Unit holders by the Trustee. 
 THE TRUST Duties and Limited Powers of Trustee The duties of the Trustee are as specified in the Trust Agreement and by the laws of the State
of Delaware. The discussion of terms of the Trust Agreement contained herein do not purport to be
complete and are qualified in their entirety by reference to the Trust Agreement itself, which is
filed as an exhibit to this report and is available upon request from the Trustee. The basic function of the Trustee is to collect income from the Royalty Interest, to pay from
the Trusts income and assets all expenses, charges and obligations of the Trust, and to pay
available cash to holders of Units. The Bank of New York (Delaware) has been appointed co-trustee
in order to satisfy certain requirements of the Delaware Trust Act, but The Bank of New York alone
is able to exercise the rights and powers granted to the Trustee in the Trust Agreement. The Trust Agreement grants the Trustee only such rights and powers as are necessary to achieve
the purposes of the Trust. The Trust Agreement prohibits the Trust from engaging in any business,
any commercial activity or, with certain exceptions, investment activity of any kind and from using
any portion of the assets of the Trust to acquire any oil and gas lease, royalty or other mineral
interest. The Trustee has the right to establish a cash reserve for the payment of material liabilities
of the Trust which may become due. Such reserve can only be set up when the Trustee has determined
that it is not practical to pay such liabilities in a subsequent quarter out of funds anticipated
to be available and that, in the absence of such reserve, the Trust Estate 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. Furthermore, the Trustee must receive an unqualified written opinion of counsel to
the effect that such reserve 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 unless the Trustee is unable to
obtain such opinion and determines that the failure to establish such reserve will 2




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be materially detrimental to the Unit holders considered as a whole or will subject the
Trustee to the risk of personal liability for such liabilities. The Trustee has a limited power to borrow on behalf of the Trust on a secured or unsecured
basis. Such borrowing may be effected if at any time the amount of cash on hand is not sufficient
to pay liabilities of the Trust then due. The Trustee can only borrow from an entity not
affiliated with the Trustee. Certain other conditions must also be satisfied, including that the
Trustee must determine that it is not practical to pay such liabilities in a subsequent quarter out
of funds anticipated to be available and the Trust Estate is subject to the risk of loss or
diminution in value. The borrowing must be effected pursuant to terms which (in the opinion of an
investment banking firm or commercial banking firm) are commercially reasonable when compared to
other available alternatives and the Trustee must receive an unqualified written opinion of counsel
to the effect that such borrowing 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, unless the Trustee is unable to
obtain such opinion and determines that the failure to effect such borrowing will be materially
detrimental to the Unit Holders considered as a whole. To secure payment of borrowings by the
Trust, the Trustee is authorized to mortgage, pledge, grant security interests in or otherwise
encumber the Trust Estate or any portion thereof (including the Royalty Interest), and to carve out
and convey production payments. The borrowing itself and the pledges or other encumbrances to
secure borrowings are permitted without a vote of Unit holders. In the event of such borrowings,
no further Trust distributions may be made until the indebtedness created by such borrowings has
been paid in full. The Trustee may sell Trust properties only as authorized by the affirmative vote of the
holders of Units representing 70 percent of the Units outstanding, provided, however, that if such
sale is effected in order to provide for the payment of specific liabilities of the Trust then due
and involves a part, but not all or substantially all, of the Trust Estate, such sale shall be
approved by the affirmative vote of a majority of the holders of the Units. The Trustee may also sell the Trust Estate, or a portion thereof, for cash if such sale is
effected in order to provide for the payment of specific liabilities of the Trust then due, cash on
hand is insufficient and the Trustee is unable to effect a borrowing by the Trust. The Trustee
must also determine that the failure to pay such liabilities at a later date will be contrary to
the best interest of the holders of Units and that it is not practicable to submit the sale to a
vote of the Unit holders. The sale must be effected at a price which (in the opinion of an
investment banking firm or commercial banking firm) is at least equal to the fair market value of
the interest sold and is effected pursuant to commercially reasonable terms when compared to other
available alternatives. The Trustee must receive an unqualified written opinion of counsel to the
effect that the 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 unless the Trustee is unable to obtain such
opinion and determines that the failure to effect such sale will be materially detrimental to the
Unit Holders considered as a whole. Finally, the Trustee may sell the Trust Estate upon
termination of the Trust. Any sale of Trust properties must be for cash unless otherwise authorized by the holders of
Units. 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. Except in certain circumstances, the Trustee is entitled to be indemnified out of the assets
of the Trust for any liability, expense, claim, damage or other loss incurred by it in the
performance of its duties unless such loss results from its negligence, bad faith or fraud or from its expenses in
carrying out such duties exceeding the compensation and reimbursement it is entitled to under the
Trust Agreement. 3




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Employees The Trust has no employees. All administrative functions of the Trust are performed by the
Trustee. Property of the Trust Except for cash
and cash equivalents held by the Trustee from time to time, the property of the Trust
 consists exclusively of the Royalty Interest.  The Royalty Interest was conveyed to
the Trust by an Overriding Royalty Conveyance dated February 27, 1989 from the Company
to Standard Oil and a Trust
 Conveyance dated February 28, 1989 from Standard Oil to the Trust.
 The Overriding Royalty Conveyance and the Trust Conveyance are referred
 to collectively herein as the Conveyance. For a description of the terms of the Royalty
Interest, see THE ROYALTY INTEREST below.  The discussion of the terms of the Conveyance
 herein is qualified in its entirety by reference to the relevant provisions of the Overriding
Royalty Conveyance and the Trust Conveyance which are filed with the SEC as exhibits to
this report. The interest conveyed to the Trust by the Conveyance is an overriding royalty interest
consisting of the right to receive a Per Barrel Royalty for each Barrel of Royalty Production. The
meaning of these terms is more fully described below under THE ROYALTY INTEREST. The Trust does
not have the right to take oil and gas in kind. The Royalty Interest constitutes a non-operational interest in minerals. The Trust has no
right to take over operations or to share in any operating decision whatsoever with respect to the
Companys working interest in the Prudhoe Bay Unit. The Company is not obligated to continue to
operate any well or maintain in force or attempt to maintain in force any portion of its working
interest in the Prudhoe Bay Unit when, in its reasonable and prudent business judgment, such well
or interest ceases to produce or is not capable of producing oil or gas in paying quantities. Under the terms of the Prudhoe Bay Unit Operating Agreement, if the Company fails to pay any
costs and expenses chargeable to the Company 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 the Company agreed to pay timely 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 expense, claim, damage, loss or liability incurred by the Company or others
attributable to the Companys working interest in the Prudhoe Bay Unit or to the oil produced from
it, and the Company has agreed to indemnify the Trust and hold it harmless against any such
impositions. The Company 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 its working interest in
the exercise of its reasonable and prudent business judgment without liability to the Trust. The
Company also has the right to sell or assign all or any part of its working interest in the Prudhoe
Bay Unit, so long as the sale or assignment is expressly made subject to the Royalty Interest and
the terms and provisions of the Conveyance. Amendment of the Trust Agreement The Trust Agreement may be amended without a vote of the holders of Units to cure an
ambiguity, to correct or supplement any provision of the Trust Agreement that may be inconsistent
with 4




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any other such provision or to make any other provision with respect to matters arising under
the Trust Agreement that do not adversely affect the holders of Units. The Trust Agreement may
also be amended with the approval of a majority of the outstanding Units at a meeting of holders of
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 and by the Trustee, or
reduce or delay the distributions to the holders of Units or effect certain other changes unless
approved by the affirmative vote of holders of at least 80 percent of the outstanding Units and by
the Trustee. 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. Resignation or Removal of Trustee The Trustee may resign at any time or be removed with or without cause by the holders of a
majority of the outstanding Units. Its successor must be a corporation organized and doing
business under the laws of the United States, any state thereof or the District of Columbia,
authorized under such laws to exercise trust powers, 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 the State of
Delaware, then any successor trustee will be such a resident or have such a principal office. No
resignation or removal of the Trustee shall become effective until a successor trustee shall have
accepted appointment. Liabilities and Reserve
for Contingencies 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 incurred by the Trust are routine administrative
expenses, such as Trustees fees, and accounting, legal and other professional fees. The Trustee is obligated to borrow funds required to pay liabilities of the Trust when due,
and to pledge or otherwise encumber the Trusts assets, if it determines that the cash on hand is
insufficient to pay such liabilities and that it is not practical to pay such liabilities out of
funds anticipated to be available for subsequent quarterly distributions. Borrowings must be
repaid in full before any further distributions are made to holders of Units. As discussed above
under Duties and Limited Powers of Trustee, under certain circumstances the Trustee may establish
a cash reserve for the payment of material liabilities of the Trust. In 1999, the Trustee established a $1,000,000 cash
reserve to provide liquidity to the Trust during any future periods in which the Trust does not
receive a distribution. See Item 7 in Part II below. Termination of the Trust The Trust is irrevocable and the Company has no power to terminate the Trust. The Trust will
terminate: (a) on or prior to December 31, 2010 upon a vote of holders of not less than 70 percent
of the outstanding Units, or (b) after December 31, 2010 either (i) at such time as 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 such period have been materially and adversely affected by an
event constituting force majeure, or (ii) upon a vote of holders of not less than 60 percent of the
outstanding Units. 5




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Upon termination of the Trust, the Company will have an option to purchase the Royalty
Interest (for cash unless holders representing 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) at a price equal to the greater of (i) the fair market value of the Trust Estate 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. If the
Units are neither listed nor traded in the over-the-counter market, the price will be the fair
market value of the trust estate as set forth in the opinion mentioned above. If the Company does not exercise its option, the Trustee will sell the Trust properties
pursuant to procedures or material 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 such procedures or terms to a vote of
the holders of Units, and the sale is effected at a price which is at least equal to the fair
market value of the trust estate as set forth in the opinion mentioned above and pursuant to terms
and conditions deemed commercially reasonable by the investment banking firm, commercial banking
firm or other entity rendering such opinion. After satisfying all existing liabilities and establishing adequate reserves for the payment
of contingent liabilities, the Trustee will distribute all available proceeds to the holders of
Units. In the Trust Agreement, holders of Units have waived the right to seek or secure any portion
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. Voting Rights of Holders of Units Although holders of Units possess certain voting rights, their voting rights are not
comparable to those of shareholders of a corporation. For example, there is no requirement for
annual meetings of holders of Units or annual or other periodic reelection of the Trustee. A meeting of the holders of Units may be called at any time to act with respect to any matter
which the holders of Units are authorized to act pursuant to the Trust Agreement. Any such meeting
may be called by the Trustee in its discretion and will be called (i) as soon as practicable after
receipt of a written request by the Company or (ii) as soon as practicable after receipt of a
written request that sets forth in reasonable detail the action proposed to be taken at such
meeting and is signed by holders of Units owning not less than 25 percent of the then outstanding
Units or (iii) as may be required by applicable laws or regulations of the New York Stock Exchange.
All such meetings are required to take place in the Borough of Manhattan, The City of New York. 
 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 to which the Royalty Interest
is entitled. The royalty payable to the Trust under the Royalty Interest for each calendar quarter
is the sum of the 6




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product of (i) the Royalty Production and (ii) the Per Barrel Royalty for each
day in the quarter. 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
the Companys working interest in the Prudhoe Bay Unit for such calendar quarter, net of the State
of Alaska royalty and less the value of any applicable payments made to affiliates of the Company. Royalty Production The Royalty Production for each day in a calendar quarter is 16.4246 percent of the first
90,000 Barrels of the actual average daily net production of oil and condensate for such quarter
from the Prudhoe Bay (Permo-Triassic) Reservoir and allocated to the oil and gas leases owned by
the Company in the Prudhoe Bay Unit as of February 28, 1989 or as modified thereafter by any
redetermination provided under the terms of the Prudhoe Bay Unit Operating Agreement and the
Prudhoe Bay Unit Agreement (the Subject Leases). 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 Subject
Leases for any calendar quarter is the total production of oil and condensate for such quarter, net
of the State of Alaska royalty, divided by the number of days in such quarter. Per Barrel Royalty The Per Barrel Royalty in effect for any day is an amount equal to the WTI Price for such
day less the sum of (i) the product of the Chargeable Costs multiplied by the Cost Adjustment
Factor and (ii) Production Taxes. Based on the WTI Price on December 31, 2004, current Production
Taxes and Chargeable Costs adjusted in accordance with the Conveyance, the Company estimates that
Per Barrel Royalty payments will continue through the year 2019. WTI Price The WTI Price for any trading day means (i) the latest price (expressed in dollars per
Barrel) for West Texas intermediate crude oil of standard quality having a specific gravity of 40
degrees API for delivery at Cushing, Oklahoma (West Texas Crude), quoted for such trading day by
the Dow Jones International Petroleum Report (which is published in The Wall Street Journal) or if
the Dow Jones International Petroleum Report does not publish such quotes, then such price as
quoted by Reuters, or if Reuters does not publish such quotes, then such price as quoted in Platts
Oilgram Price Report, or (ii) if for any reason such publications do not publish the price of West
Texas Crude, then the WTI Price will mean, until the price quotations described in (i) are again
available, the simple average of the daily mean prices (expressed in dollars per Barrel) quoted for
West Texas Crude by one major oil company, one petroleum broker and one petroleum trading company,
in each case unaffiliated with BP and having substantial U.S. operations. Such major oil company,
petroleum broker and petroleum trading company will be designated by the Company from time to time.
In the event that prices for West Texas Crude are not quoted so as to permit the calculation of
the WTI Price, West Texas Crude, for the purposes of calculating the WTI Price will mean such
other light sweet domestic crude oil of standard quality as is designated by the Company and
approved by the Trustee in the exercise of its reasonable judgment, with appropriate allowance for
transportation costs to the Gulf Coast (or other appropriate location) to equilibrate such 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. 7




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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 the Companys actual costs of
production. Chargeable Costs per Barrel for the five calendar years ended December 31, 2004 were:
$10.00 during 2000; $10.75 during 2001; $11.25 during 2002; $11.75 during 2003 and $12.00 during
2004. Chargeable Costs for the calendar year ending December 31, 2005 and subsequent years are
shown in the following table: For the
    
    
    
    For theYear Ending
    
    Chargeable Costs
    
    Year Ending
    
    Chargeable CostsDecember 31
    
    Per Barrel
    
    December 31
    
    Per Barrel2005
    
    $12.25
    
    2013
    
    $16.802006
    
    12.50
    
    2014
    
    16.902007
    
    12.75
    
    2015
    
    17.002008
    
    13.00
    
    2016
    
    17.102009
    
    13.25
    
    2017
    
    17.202010
    
    14.50
    
    2018
    
    20.002011
    
    16.60
    
    2019
    
    23.752012
    
    16.70
    
    2020
    
    26.50
 After 2020, Chargeable Costs increase at a uniform rate of $2.75 per year. Chargeable Costs will be reduced by up to $1.20 per Barrel in 2006 and subsequent years if,
between January 1, 2001 and December 31, 2005, either (a) an additional 400,000,000 STB of proved
reserves (before taking into account any production therefrom) have not been added to proved
reserves allocated to the Subject Leases (including, for the purpose of this calculation, a credit
equal to the number of STB of proved reserves in excess of 300,000,000 added to the Companys
reserves after December 31, 1987 and before January 1, 2001), or (b) an additional 100,000,000 STB
of proved reserves (before taking into account any production therefrom) have not been added to the
reserves allocated to the Subject Leases, without allowing any credit for additions prior to
January 1, 2001. In general, proved reserves for purposes of this determination consist of the
Companys estimate (determined to be reasonable by independent petroleum engineers) of the
quantities of crude oil and condensate that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years under existing economic and operating
conditions from the Prudhoe Bay (Permo-Triassic) Reservoir in the Prudhoe Bay Unit. See THE
PRUDHOE BAY UNIT  Reserve Estimates below. 8




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##### Table of Contents



As of December 31, 1987, the proved reserves of crude oil and condensate allocated to the
Subject Leases were 2,035.6 million STB. Since that date, the Company has made the additions (and
deductions) to its estimates of proved reserves allocated to the Subject Leases (before taking into
account any production from such additions) as shown in the following table: Additions to Proved ReservesYear EndedDecember 31
    
    Annual
    
    Cumulative(Million STB)1988  1994
    
    
    
    668.01995
    
    92.2
    
    760.21996
    
    (21.0)
    
    739.21997
    
    (1.5)
    
    737.71998
    
    (0.5)
    
    737.21999
    
    0.0
    
    737.22000
    
    57.3
    
    794.52001
    
    20.5
    
    815.02002
    
    0.0
    
    815.02003
    
    0.0
    
    815.02004
    
    127.0
    
    942.0
 Additional drilling, workovers, facilities modifications, new recovery projects and programs
for production enhancement and optimization may mitigate, but not eliminate the recent decline in
gross oil and condensate production capacity.However, significant downward revisions of proved
reserve estimates could result in a reduction of Chargeable Costs being required as described above
in the year 2006 and thereafter. Cost Adjustment Factor The Cost Adjustment Factor is the ratio of (i) the Consumer Price Index published for the
most recently past February, May, August or November, as the case may be, to (ii) 121.1 (the
Consumer Price Index for January 1989), except that (a) if for any calendar quarter the average WTI
Price is $18.00 or less, then the Cost Adjustment Factor for that quarter will be the Cost
Adjustment Factor for the immediately preceding quarter, and (b) the Cost Adjustment Factor for any
calendar quarter in which the average WTI Price exceeds $18.00, after a calendar quarter during
which the average WTI Price is equal to or less than $18.00, and for each following calendar
quarter in which the average WTI Price is greater than $18.00, will be the product of (x) the Cost
Adjustment Factor for the most recently past calendar quarter in which the average WTI Price is
equal to or less than $18.00 and (y) a fraction, the numerator of which will be the Consumer Price
Index published for the most recently past February, May, August or November, as the case may be,
and the denominator of which will be the Consumer Price Index published for the most recently past
February, May, August or November during a quarter in which the average WTI Price is equal to or
less than $18.00. 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. 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 9




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##### Table of Contents



production, delivery or sale of Royalty Production. Such taxes are computed at defined
statutory rates. In the case of taxes based upon wellhead or field value, the Conveyance provides
that the WTI Price less the product of $4.50 and the Cost Adjustment factor will be deemed to be
the wellhead or field value. At the present time, the Production Taxes payable with respect to the
Royalty Production are the Alaska Oil and Gas Properties Production Tax (Alaska Production Tax).
For the purposes of the Royalty Interest, the Alaska Production Tax is computed without regard to
the economic limit factor, if any, as the greater of the percentage of value amount (based on
the statutory rate and the wellhead value as defined above) and the cents per Barrel amount. As
of the date of this report, the statutory rate for the purpose of calculating the percentage of
value amount is 15 percent. A surcharge to the Alaska Production Tax increased Production Taxes
by $0.05 per Barrel of net production effective July 1, 1989. Due to the spill response fund
reaching $50 million in 1995, $0.02 per Barrel of the surcharge has been indefinitely suspended.
In the event the balance of the spill response fund falls below $50 million, the $0.02 per Barrel
surcharge will be reinstated until the fund balance again reaches $50 million. The remaining $0.03
per Barrel surcharge is not affected by the funds balance and will continue to be imposed at all
times. Per Barrel Royalty Calculations The following table shows how the above-described factors interacted during each of the past
five years to produce the Per Barrel Royalty paid for each of the calendar quarters indicated. See THE UNITS  Distributions of Income below. Cost
    
    
    AdjustedAverage
    
    
    Chargeable
    
    
    Adjustment
    
    
    Chargeable
    
    
    Production
    
    
    Per BarrelWTI Price
    
    
    Costs
    
    
    Factor
    
    
    Costs
    
    
    Taxes
    
    
    Royalty2000:1st Qtr
    
    $
    28.86
    
    
    $
    10.00
    
    
    
    1.307
    
    
    $
    13.07
    
    
    $
    3.48
    
    
    $
    12.312nd Qtr
    
    
    28.87
    
    
    
    10.00
    
    
    
    1.319
    
    
    
    13.19
    
    
    
    3.47
    
    
    
    12.213rd Qtr
    
    
    31.63
    
    
    
    10.00
    
    
    
    1.330
    
    
    
    13.30
    
    
    
    3.88
    
    
    
    14.454th Qtr
    
    
    31.98
    
    
    
    10.00
    
    
    
    1.341
    
    
    
    13.41
    
    
    
    3.92
    
    
    
    14.662001:1st Qtr
    
    
    28.83
    
    
    
    10.75
    
    
    
    1.354
    
    
    
    14.55
    
    
    
    3.44
    
    
    
    10.842nd Qtr
    
    
    27.92
    
    
    
    10.75
    
    
    
    1.368
    
    
    
    14.71
    
    
    
    3.29
    
    
    
    9.923rd Qtr
    
    
    26.82
    
    
    
    10.75
    
    
    
    1.367
    
    
    
    14.69
    
    
    
    3.13
    
    
    
    9.004th Qtr
    
    
    20.41
    
    
    
    10.75
    
    
    
    1.366
    
    
    
    14.68
    
    
    
    2.17
    
    
    
    3.562002:1st Qtr
    
    
    21.67
    
    
    
    11.25
    
    
    
    1.369
    
    
    
    15.40
    
    
    
    2.36
    
    
    
    3.912nd Qtr
    
    
    26.28
    
    
    
    11.25
    
    
    
    1.384
    
    
    
    15.57
    
    
    
    3.04
    
    
    
    7.673rd Qtr
    
    
    28.33
    
    
    
    11.25
    
    
    
    1.391
    
    
    
    15.65
    
    
    
    3.34
    
    
    
    9.344th Qtr
    
    
    28.25
    
    
    
    11.25
    
    
    
    1.396
    
    
    
    15.70
    
    
    
    3.33
    
    
    
    9.222003:1st Qtr
    
    
    34.08
    
    
    
    11.75
    
    
    
    1.410
    
    
    
    16.57
    
    
    
    4.19
    
    
    
    13.322nd Qtr
    
    
    29.07
    
    
    
    11.75
    
    
    
    1.413
    
    
    
    16.60
    
    
    
    3.44
    
    
    
    9.033rd Qtr
    
    
    30.30
    
    
    
    11.75
    
    
    
    1.421
    
    
    
    16.70
    
    
    
    3.62
    
    
    
    9.984th Qtr
    
    
    31.23
    
    
    
    11.75
    
    
    
    1.421
    
    
    
    16.69
    
    
    
    3.76
    
    
    
    10.78
 10




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##### Table of Contents



Cost
    
    
    AdjustedAverage
    
    
    Chargeable
    
    
    Adjustment
    
    
    Chargeable
    
    
    Production
    
    
    Per BarrelWTI Price
    
    
    Costs
    
    
    Factor
    
    
    Costs
    
    
    Taxes
    
    
    Royalty2004:1st Qtr
    
    $
    35.18
    
    
    $
    12.00
    
    
    
    1.434
    
    
    $
    17.20
    
    
    $
    4.34
    
    
    $
    13.642nd Qtr
    
    
    38.31
    
    
    
    12.00
    
    
    
    1.456
    
    
    
    17.47
    
    
    
    4.79
    
    
    
    16.053rd Qtr
    
    
    43.78
    
    
    
    12.00
    
    
    
    1.459
    
    
    
    17.51
    
    
    
    5.61
    
    
    
    20.664th Qtr
    
    
    48.35
    
    
    
    12.00
    
    
    
    1.471
    
    
    
    17.65
    
    
    
    6.29
    
    
    
    24.41
 Potential Conflicts of Interest The interests of the Company and the Trust with respect to the Prudhoe Bay Unit could at times
be different. In particular, because the Per Barrel Royalty is based on the WTI Price and
Chargeable Costs rather than the Companys actual price realized and actual costs, the actual per
Barrel profit received by the Company on the Royalty Production could differ from the Per Barrel
Royalty to be paid to the Trust. It is possible, for example, that the relationship between the
Companys actual per Barrel revenues and costs could be such that the Company may determine to
interrupt or discontinue production in whole or in part even though a Per Barrel Royalty may
otherwise have been payable to the Trust pursuant to the Royalty Interest. This potential conflict
of interest could affect the royalties paid to Unit holders, although the Company will be subject
to the terms of the Prudhoe Bay Unit Operating Agreement. 
 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 the Company, 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 equity securities. Distributions of Income The Company 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, to the extent possible, pays all expenses of the Trust for each quarter on the
Quarterly Record Date. The Trustee then distributes an amount equal to the excess, if any, of the
cash received by the Trust from the Royalty Interests over the expenses and payments of liabilities
of the Trust, subject to adjustments for changes made by the Trustee in any cash reserve
established for the payments of estimated liabilities of the Trust (the Quarterly Distribution)
to the persons in whose names the Units were registered at the close of business on the immediately
preceding Quarterly Record Date. The Trust Agreement provides that the Trustee shall pay the Quarterly Distribution on the
fifth day after the Trustees receipt of the amount paid by the Company on the Quarterly Record
Date, and that collected cash balances being held by the Trustee for distribution shall be invested
in obligations issued or unconditionally guaranteed by the United States or any agency or
instrumentality thereof and secured by the full faith and credit of the United States (Government
Obligations) or, if Government Obligations with a maturity date on the date of the distribution to
Unit holders are not available, in repurchase 11




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##### Table of Contents



agreements with banks having capital, surplus and
undivided profits of $100,000,000 or more (which may include The Bank of New York) secured by
Government Obligations. If time does not permit the Trustee to invest collected funds in
investments of the type described in the preceding sentence, the Trustee may invest such funds
overnight in a time deposit with a bank meeting the foregoing requirement (including The Bank of
New York). Reports to Unit Holders Within 90 days after the end of each calendar year, the Trustee mails to the holders of record
of Units at any time during the calendar year a report 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 to holders of Units an
annual report containing audited financial statements of the Trust, a letter of the independent
petroleum engineers engaged by the Trust setting forth a summary of such firms determinations
regarding the Companys estimates of proved reserves and other related matters, and certain other
information required by the Trust Agreement. Following the end of each quarter, the Trustee mails Unit holders a quarterly report showing
the assets and liabilities, receipts and disbursements and income and expenses of the Trust and the
Royalty Production for such quarter. Limited Liability of Unit Holders The Trust Agreement provides that the holders of Units 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, the Trust Agreement 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 holders, the following procedures will be applicable: (i) The Trustee will give written notice of the existence of such proceedings to each
holder whose nationality or other status is an issue in the proceeding. The notice will
contain a reasonable summary of such proceeding and will constitute a demand to each such
holder that he dispose of his Units within 30 days to a party not of the nationality or
other status at issue in the proceeding described in the notice. (ii) If any holder fails to dispose of his Units in accordance with such notice, the
Trustee will redeem, at any time during the 90-day period following the termination of the
30-day period specified in the notice, any Unit not so transferred for a cash price per Unit
equal to the closing price of the Units on the stock exchange on which the Units are then listed
or, in the absence of any such listing, the closing bid price on the NASDAQ National Market
System if the Units are so quoted or, if not, the mean between the closing bid and asked
prices for the Units in the over-the-counter market, in either case as of the last business
day prior to the expiration of the 30-day period stated in the notice. If the Units are
neither listed nor traded in the over-the-counter market, the price will be the fair market
value of the Units as determined by a recognized firm of investment bankers or other
competent advisor or expert. 12




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##### Table of Contents



Units redeemed by the Trustee will be cancelled. The Trustee may, in its sole discretion,
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
ERISA, or under the Internal Revenue Code of 1986, the Units subject to the Trustees right of
redemption will be purchased by the Company or a designee thereof, at the above described purchase
price. Issuance of Additional Units The Trust Agreement provides that the Company 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, including receipt by the Trustee of a ruling from the Internal Revenue
Service to the effect that neither the existence nor the exercise of the right to assign the
additional royalty interest or the power to accept such assignment will adversely affect the
classification of the Trust as a grantor trust for federal income tax purposes, the Trust may
issue up to an additional 18,600,000 Units. The Company has not conveyed any additional royalty
interests to the Trust, and the Trust has not issued any additional Units, since the inception of
the Trust. 
 THE BP SUPPORT AGREEMENT BP has agreed pursuant to the terms of a Support Agreement, dated February 28, 1989, among BP,
the Company, Standard Oil and the Trust (the Support Agreement), to provide financial support to
the Company in meeting its payment obligations under the Royalty Interest. Within 30 days of notice to BP, BP will ensure that the Company is in a position to perform
its payment obligations under the Royalty Interest and to satisfy its payment obligations to the
Trust under the Trust Agreement, including contributing to the Company such funds as are necessary
to make such payments. BPs obligations under the Support Agreement are unconditional and directly
enforceable by Unit holders. Except as described below, no assignment, sale, transfer, conveyance, mortgage or pledge or
other disposition of the Royalty Interest will relieve BP of its obligations under the Support
Agreement. Neither BP nor the Company may transfer or assign its rights or obligations under the Support
Agreement without the prior written consent of the Trust, except that BP can arrange for its
obligations under the Support Agreement to be performed by any affiliate of BP, provided that BP
remains responsible for ensuring that such obligations are performed in a timely manner. The Company 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 the Company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 the Companys working interest in the Prudhoe Bay Unit if the
transferee agrees to assume and be bound by BPs obligation under the Support Agreement in a
writing reasonably satisfactory to the Trustee and if the transferee is an entity having a rating
assigned to outstanding unsecured, unsupported long term debt from Moodys Investors Service, Inc.
of at least A3 or from Standard & Poors of at least A- or an equivalent rating from at least one
nationally-recognized statistical rating organization (after giving effect to the sale or transfer
to such entity of all or substantially all of the Companys working interest in the Prudhoe Bay
Unit and the assumption by such entity of all of the Companys obligations under the Conveyance and
of all BPs obligations under the Support Agreement). 13




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##### Table of Contents



THE PRUDHOE BAY UNIT General The Prudhoe Bay field (the Field) is located on the North Slope of Alaska, 250 miles north
of the Arctic Circle and 650 miles north of Anchorage. The Field extends approximately 12 miles by
27 miles and contains nearly 150,000 productive acres. The Field, which was discovered in 1968 by
BP and others, has been in production since 1977. The Field is the largest producing oil field in
North America. As of December 31, 2004, approximately 10.7 billion STB of oil and condensate had
been produced from the Field. Field development is well advanced with approximately $18.8 billion
gross capital spent and a total of about 2,138 wells drilled. Other large fields located in the
same area include the Kuparuk, Endicott, and Lisburne fields. Production from those fields is not
included in the Royalty Interest. 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 (collectively, PESS) formations. Underlying the Sadlerochit Group are the
oil-bearing Lisburne and Endicott formations. The net production referred to herein 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 produced oil from the reservoir is a medium grade, low sulfur crude with an average
specific gravity of 27 degrees API. The gas cap composition is such that, upon surfacing, a liquid
hydrocarbon phase, known as condensate, is formed. 14




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##### Table of Contents



The interests of the Unit holders are 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. Prudhoe Bay Unit Operation and Ownership Since several oil companies hold acreage within the Field, the Prudhoe Bay
Unit was established to optimize Field development.
 Other Field owners include affiliates of Exxon Mobil Corporation
(Exxon Mobil), ConocoPhillips, ChevronTexaco Corporation and Forest
Oil Corporation.  The Prudhoe Bay Unit Operating Agreement specifies
the allocation of production and costs to the Prudhoe Bay Unit owners.
The Prudhoe Bay Unit, which became effective on April 1, 1977, divided the Field into two
operating areas.  Prior to July 1, 2000, the Company was the operator of the Western Operating
 Area and Arco Alaska Inc., a subsidiary of the Atlantic Richfield Company, was the operator of
 the Eastern Operating Area.  Oil and condensate production came from both the Western Operating
 Area and the Eastern Operating Area.  On July 1, 2000, following the acquisition by BP of
Atlantic Richfield Company, the Company became the sole operator of the Field. The Prudhoe Bay Unit Operating Agreement specifies the allocation of production and costs to
the working interest owners. The Prudhoe Bay Unit Operating Agreement also defines operator
responsibilities and voting requirements and is unusual in its establishment of separate
participating areas for the gas cap and oil rim. The ownership of the Prudhoe Bay Unit by participating area as of December 31, 2004 is
summarized in the following table: Oil Rim
    
    
    Gas CapBP
    
    
    26.35
    %(a)
    
    
    26.35
    %(b)Exxon Mobil
    
    
    36.40
    
    
    
    36.40ConocoPhillips
    
    
    36.07
    
    
    
    36.07Others
    
    
    1.18
    
    
    
    1.18Total
    
    
    100.00
    %
    
    
    100.00
    %
 _______________  (a)
    The Trusts share of oil production is computed based on BPs ownership interest in the
oil rim participating area of 50.68 percent as of February 28, 1989. Subsequent decreases
in the Companys participation in oil rim ownership do not affect calculation of Royalty
Production from the Subject Leases and have not decreased the Trusts Royalty Interest.  (b)
    The Trusts share of condensate production is computed based on BPs ownership interest
in the gas cap participating area of 13.84 percent as of February 28, 1989. Subsequent
increases in the Companys gas cap ownership do not affect calculation of Royalty
Production from the Subject Leases and have not increased the Trusts Royalty Interest. Historical Production Production
from the Field began on June 19, 1977, with the completion of the Trans Alaska Pipeline System.
The pipeline has a capacity of approximately 1.4 million STB of oil per day. As of December 31, 2004 there were about 1,109 active producing oil wells, 33 gas reinjection
wells, 82 water injection wells and 136 water and miscible gas injection wells in the Field. In
terms of individual well performance, oil production rates range from
one STB to 4,500 STB of oil per
day. Currently, the average well production rate is about 317 STB of oil per day. The Companys share of the hydrocarbon liquids production from the Field includes oil,
condensate and natural gas liquids. Using the production allocation procedures from the Prudhoe
Bay 15




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##### Table of Contents



Unit Operating Agreement, the Fields production and the share of oil and condensate (net of
State of Alaska royalty) allocated to the Subject Leases have been as follows during the periods
indicated: Oil
    
    
    CondensateYear Ended
    
    
    
    
    
    Subject
    
    
    
    
    
    
    SubjectDecember 31
    

Total
Field
    
    
    Leases
    
    
    Total Field
    
    
    Leases(Thousand STB per day)2000
    
    
    364.0
    
    
    
    161.4
    
    
    
    146.7
    
    
    
    17.82001
    
    
    324.9
    
    
    
    144.1
    
    
    
    131.2
    
    
    
    15.92002
    
    
    293.8
    
    
    
    130.3
    
    
    
    121.5
    
    
    
    14.72003
    
    
    273.2
    
    
    
    121.2
    
    
    
    113.8
    
    
    
    13.82004
    
    
    243.4
    
    
    
    107.9
    
    
    
    109.0
    
    
    
    13.2
 Transportation of Prudhoe Bay Oil Production from the Field is carried to Pump Station 1, which is the starting point for the
Trans Alaska Pipeline System, through two 34-inch diameter transit lines, one from each half of the
Field. At Pump Station 1, Alyeska Pipeline Service Company, the pipeline operator, meters the oil
and pumps it south in the 48-inch diameter pipeline to Valdez where it is either loaded onto marine tankers or stored temporarily.
It takes the oil about seven days to make the trip. 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 Field reserves. Several different oil recovery mechanisms are currently active in the 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 The net proved remaining reserves of oil and condensate associated with the Subject Leases is
approximately 941.4 million STB as of December 31, 2004. This current estimate of reserves is
based upon various assumptions, including a reasonable estimate of the allocation of hydrocarbon
liquids between oil and condensate pursuant to the procedures of the Prudhoe Bay Unit Operating
Agreement. 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. The Company
anticipates that net production from current proved reserves allocated to the Subject Leases will
exceed 90,000 Barrels per day until the year 2013. The occurrence of major gas sales could
accelerate the time at which the Companys net production would fall below 90,000 Barrels per day,
due to the consequent decline in reservoir pressure. The Company also projects continued economic
production thereafter, at a declining rate, until the year 2050; however, for the economic
conditions and production forecast as of December 31, 2004, it is estimated that royalty payments
will cease following the year 2019. The Companys reserve estimates and production assumptions and projections are predicated upon
a reasonable estimate of hydrocarbon allocation between oil and condensate. Oil and condensate are
physically produced in a commingled stream of hydrocarbon liquids. The allocation of hydrocarbon 16




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##### Table of Contents



liquids between the oil and condensate from the 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 Subject Leases will vary over time according to the proportions of
hydrocarbon liquid being allocated as condensate or as oil under the Prudhoe Bay Unit Operating
Agreement allocation procedures. 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 billion 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 Subject Leases. The Company has estimated that the net remaining
proved reserves attributable to the Trust as of December 31, 2004 were 77.4 million Barrels of oil
and condensate. Using procedures specified in Financial Accounting Standards Board Statement of
Financial Standards No. 69, the Company calculated that as of December 31, 2004 production of oil
and condensate from the proved reserves allocated to the Trust will result in estimated future net
revenues to the Trust of $1,130.9 million, with a present value of $676.3 million. The Company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. There is no precise method of forecasting the allocation of reserve volumes between the
Company 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 Field. 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 Field 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 Subject Leases, the net proved reserves allocated to the Trust, and the WTI Prices on the dates
indicated: Net Proved Reserves
    
    
    WTI PriceDecember 31
    
    Subject Leases (a)
    
    
    Trust (b)
    
    
    Per Barrel(Million STB)2000
    
    
    999.6
    
    
    
    90.7
    
    
    $
    26.832001
    
    
    961.7
    
    
    
    43.2
    
    
    
    19.782002
    
    
    908.7
    
    
    
    85.8
    
    
    
    31.232003
    
    
    858.7
    
    
    
    77.9
    
    
    
    32.552004
    
    
    941.4
    
    
    
    77.4
    
    
    
    43.46
  (a)
    Includes proved undeveloped reserves of 137.3 million STB at December 31, 2000; 112.5
million STB at December 31, 2001; 5.5 million STB at December 31, 2002; 139.9 million STB
at December 31, 2003; and 115.4 million STB at December 31, 2004.  (b)
    Includes proved undeveloped reserves of 6.4 million STB at December 31, 2000; 0.03
million STB at December 31, 2002; 11.0 STB at December 31, 2003; and 9.1 million STB at
December 31, 2004. No proved undeveloped reserves were attributable to the Trust at
December 31, 2001. 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 17




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Consumer Price Index and no future additions by the Company of proved reserves.
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 6 (unaudited) of the Notes to Financial Statements in Item 8. The Company 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. However, several such investments
which would augment Prudhoe Bay projects are already in progress. These include additional
drilling, water flood expansions and miscible injection continuation/expansion projects. Other
possible investments could include expanded gas cycling, miscible/water flood infill drilling,
miscible injection supply increases to peripheral areas, heavy oil tar recovery and development of
the smaller reservoirs. While there is no assurance that the Prudhoe Bay Unit working interest
owners will make any such investments they do regularly assess the technical and economic
attractiveness of implementing further projects to increase Prudhoe Bay Unit proved reserves. In the event of changes in the Company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. 18




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INDEPENDENT OIL AND GAS CONSULTANTS REPORT (Miller and Lents Letterhead) February 21, 2005 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, andFuture Net Revenues for theBP Prudhoe Bay Royalty TrustAs of December 31, 2004
 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, 2004. 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 are summarized in the report prepared by BP
Exploration (Alaska) Inc. and transmitted with a cover letter dated February 18, 2005 addressed to
Mr. Remo J. Reale of The Bank of New York and signed by Ms. Maureen Johnson. 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 19




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MILLER AND LENTS, LTD The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
    
    February 21, 2005
 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. 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, 2004, of 77.40 million barrels of oil and condensate
are, in the aggregate, reasonable. Of the 77.40 million barrels of total Proved
Reserves, 68.29 million barrels are Proved Developed Reserves, and 9.11 million barrels are
Proved Undeveloped Reserves. 20




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MILLER AND LENTS, LTD The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
    
    February 21, 2005
  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, 2004 production of the Proved Reserves will result
in Estimated Future Net Revenues of $1,130.9 million and Present Value of Estimated
Future Net Revenues of $676.3 million to the BP Prudhoe Bay Royalty Trust. These
estimates are reasonable.  6.
    BP Exploration (Alaska) Inc. estimated that, as of December 31, 2004, 942.0
million barrels of Proved Reserves have been added to Current Reserves. This estimate
is reasonable. Current Reserves are defined in the Overriding Royalty Conveyance as net
Proved Reserves of 2,035.6 million barrels as of December 31, 1987. Net additions to
Proved Reserves after December 31, 1987 affect the Chargeable Costs that are used to
calculate the Per Barrel Royalty paid to the BP Prudhoe Bay Royalty Trust.  7.
    The BP Exploration (Alaska) Inc. projection that its net production of oil and
condensate from Proved Reserves will continue at an average rate exceeding 90,000
barrels per day until the year 2013 is reasonable. As long as the Per Barrel Royalty
has a positive value, average daily production attributable to the BP Prudhoe Bay
Royalty Trust will remain constant until the net production falls below 90,000 barrels
per day; thereafter, 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 $43.46 per barrel on December 31,
2004, 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 2019 is reasonable. BP Exploration (Alaska) Inc. expects continued
economic production at a declining rate through the year 2050; however, for the
economic conditions and production forecast as of December 31, 2004 the Per Barrel
Royalty will be zero following the year 2019. 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 21




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MILLER AND LENTS, LTD The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
    
    February 21, 2005
 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 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 2050. 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
normal 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 seven to nine 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. 22




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MILLER AND LENTS, LTD The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
    
    February 21, 2005
 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. Very truly yours, (Miller and Lents Signature) WPK/bb 23




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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, the Company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.
The Company 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 the Company has
advised that the existence of legislation and regulation has had no material adverse effect on the
Companys current method of operations, existing and future legislation and regulations cannot be
predicted. 
 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. The Company 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 24




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the Trustee should establish a reserve or borrow money to satisfy debts and liabilities
of the Trust income used to establish the reserve or to repay the loan must be reported by the Unit
holder, even though the income is not distributed to the Unit holder. The Trust makes quarterly distributions to Unit holders 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 of 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 allows the election to be made annually. 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 25




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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 person 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 2. PROPERTIES Reference is made to Item 1 for the information required by this item. 
 ITEM 3. LEGAL PROCEEDINGS There are no pending legal proceedings to which the Trust is a party or of which any of its
property is the subject. 
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of Unit holders during the fourth quarter ended December
31, 2004. 26




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PART II 
 ITEM 5. MARKET FOR THE UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS The Units are listed and traded on the New York Stock Exchange under the symbol BPT. The
following table shows the high and low sales prices per Unit on the New York Stock Exchange and the
cash distributions paid per Unit, for each calendar quarter in the two years ended December 31,
2004. DistributionsHigh
    
    
    Low
    
    
    Per Unit2003:First Quarter
    
    $
    16.39
    
    
    $
    13.61
    
    
    $
    0.580Second Quarter
    
    
    19.18
    
    
    
    13.75
    
    
    
    0.808Third Quarter
    
    
    20.19
    
    
    
    16.19
    
    
    
    0.552Fourth Quarter
    
    
    28.90
    
    
    
    19.44
    
    
    
    0.6232004:First Quarter
    
    $
    30.25
    
    
    $
    22.50
    
    
    $
    0.670Second Quarter
    
    
    32.90
    
    
    
    26.31
    
    
    
    0.846Third Quarter
    
    
    40.00
    
    
    
    32.13
    
    
    
    0.998Fourth Quarter
    
    
    50.50
    
    
    
    39.35
    
    
    
    1.304
 As of March 25, 2005, 21,400,000 Units were outstanding and were held by 826 holders of
record. No Units were purchased by the Trust or any affiliated purchaser during the year ended
December 31, 2004. Future payments of cash distributions are dependent on such factors as the prevailing WTI
Price, the relationship of the rate of change in the WTI Price to the rate of change in the
Consumer Price Index, the Chargeable Costs, the rates of Production Taxes prevailing from time to
time, and the actual production from the Prudhoe Bay Unit. See THE ROYALTY INTEREST in Item 1. 
 ITEM 6. SELECTED FINANCIAL DATA The following table presents in summary form selected financial information regarding the
Trust. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(in thousands, except per Unit amounts)Royalty revenues
    
    $
    82,682
    
    
    
    55,986
    
    
    
    33,061
    
    
    
    59,934
    
    
    
    65,026Interest income
    
    $
    11
    
    
    
    10
    
    
    
    23
    
    
    
    70
    
    
    
    92Trust administration expenses
    
    $
    976
    
    
    
    1,168
    
    
    
    822
    
    
    
    724
    
    
    
    732Expenses reserve
    
    $
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    500Cash earnings
    
    $
    81,717
    
    
    
    54,828
    
    
    
    32,262
    
    
    
    59,280
    
    
    
    63,886Cash distributions
    
    $
    81,702
    
    
    
    54,867
    
    
    
    32,246
    
    
    
    59,319
    
    
    
    63,838Cash distributions per unit
    
    $
    3.818
    
    
    
    2.564
    
    
    
    1.507
    
    
    
    2.772
    
    
    
    2.983Units outstanding
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
 27




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ITEM 7. TRUSTEES DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Cautionary Statement The Trustee, its officers or its agents on behalf of the Trustee may, from time to time, make
forward-looking statements (other than statements of historical fact). When used herein, the words
anticipates, expects, believes, intends or projects and similar expressions are intended
to identify forward-looking statements. To the extent that any forward-looking statements are
made, the Trustee is unable to predict future changes in oil prices, oil production levels,
economic activity, legislation and regulation, and certain changes in expenses of the Trust. In
addition, the Trusts future results of operations and other forward looking statements contained
in this item and elsewhere in this report involve a number of risks and uncertainties. As a result
of variations in such factors, actual results may differ materially from any forward looking
statements. Some of these factors are described below. The Trustee disclaims any obligation to
update forward looking statements and all such forward-looking statements in this document are
expressly qualified in their entirety by the cautionary statements in this paragraph. Liquidity and Capital Resources The Trust is a passive entity, and the Trustees activities are limited to collecting and
distributing the revenues from the Royalty Interest and paying liabilities and expenses of the
Trust. Generally, the Trust has no source of liquidity and no capital resources other than the
revenue attributable to the Royalty Interest that it receives from time to time. See the
discussion under THE ROYALTY INTEREST in Item 1 for a description of the calculation of the Per
Barrel Royalty, and the discussion under THE PRUDHOE BAY UNIT  Reserve Estimates and
INDEPENDENT OIL AND GAS CONSULTANTS REPORT in Item 1 for information concerning the estimated
future net revenues of the Trust. However, the Trustee does have a limited power to borrow,
establish a cash reserve, or dispose of all or part of the Trust Estate, under limited
circumstances pursuant to the terms of the Trust Agreement. See the discussion under BUSINESS 
The Trust in Item 1. In 1999, due to declines in oil prices during the fourth quarter of
1998 and the first
quarter of 1999 which resulted in the Trust not receiving cash distributions for two
quarters, the Trustee established a $1,000,000 cash reserve to provide liquidity to the Trust
 during any future periods in which the Trust does not receive a distribution. The Trustee
will draw funds from the cash reserve account during any quarter in which the quarterly
distribution received by the Trust does not exceed the liabilities and expenses of
the Trust, and will replenish the reserve from future quarterly distributions, if any.
 The Trustee anticipates that it will keep this cash reserve program in place until
 termination of the Trust. Amounts 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 the Company and paid to the holders of Units on each Quarterly Record Date. As discussed under BUSINESS  Certain Tax Considerations, amounts received by the Trust as
quarterly distributions (and earnings on investment of the cash reserve) are income to the holders
of the Units for the taxable year in which such amounts are received by the Trust and must be
reported by the holders of the Units even if a portion of such amounts are used to repay borrowings
by the Trust or add to the cash reserve and are not received by the holders of the Units. 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 28




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##### Table of Contents



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
the Companys operations during the twelve-month period ended on the preceding September 30. As long as the Companys average daily net production from the Prudhoe Bay Unit exceeds 90,000
Barrels, which the Company currently projects will continue until the year 2013, the only 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, changes in
Production Taxes, changes in the expenses of the Trust, contributions to the cash reserve and
interest earned on the cash reserve. During the years 2003 and 2004 and the period of 2005 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 2005 will depend on WTI
Prices prevailing during the remainder of the year. 2004 compared to 2003 Continued increases in world oil prices drove higher WTI Prices in the fourth quarter of 2003
and the first three quarters of 2004 (the period on which calendar 2004 cash basis revenues were
based), which averaged 22% higher during that period than during the twelve months ended September
30, 2003. As a result, royalty revenues during 2004 rose approximately 48% from 2003, and cash
distributions rose approximately 49%. Chargeable Costs per Barrel increased from $11.75 to $12.00,
beginning in the first quarter of 2004. Continued increases in the Cost Adjustment Factor,
increases in Production Taxes, which averaged approximately 27% higher during the twelve months
ended September 30, 2004 than in the prior twelve-month period, and the increase in Chargeable
Costs mitigated the effect of the increase in WTI Prices on the Trusts revenues in 2004. 2003 compared to 2002 Royalty revenues and cash distributions increased during 2003 by approximately 69% and 70%,
respectively, from 2002. The increases were due to increases in WTI Prices, commencing during 2003,
which averaged approximately 26% higher during the twelve-month period ended September 30, 2003 (on
which calendar 2003 cash basis revenues were based) than during the preceding twelve-month period.
A scheduled increase in Chargeable Costs from $11.25 to $11.75 beginning in the first quarter of
2003, a small increase in the average Cost Adjustment Factor and increases in Production Taxes,
which averaged approximately 34% higher during the twelve months ended September 30, 2003 than
during the preceding twelve months, combined to offset somewhat the effect on royalty revenues of
the higher WTI Prices during fiscal 2003. 
 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The Trust is a passive entity and except for the Trusts ability to borrow money as necessary
to pay liabilities of the Trust that cannot be paid out of cash on hand, the Trust is prohibited
from engaging in borrowing transactions. The Trust periodically holds short-term investments
acquired with funds held 29




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##### Table of Contents



by the Trust pending distribution to Unit holders and funds held in
reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of
these investments and limitations on the types of investments which may be held by the Trust, the
Trust is not subject to any material interest rate risk. The Trust does not engage in transactions
in foreign currencies which could expose the Trust or Unit holders to any foreign currency related
market risk or invest in derivative financial instruments. It has no foreign operations and holds
no long-term debt instruments. 30




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##### Table of Contents



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA BP PRUDHOE BAY ROYALTY TRUST Index To Financial Statements PageReport of Independent Registered Public Accounting Firm
    
    
    32Statements of Assets, Liabilities and Trust Corpus as of December 31, 2004 and 2003
    
    
    33Statements of Cash Earnings and Distributions for the years ended
December 31, 2004, 2003 and 2002
    
    
    34Statements of Changes in Trust Corpus for the years ended
December 31 2004, 2003 and 2002
    
    
    35Notes to Financial Statements
    
    
    36
 31




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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, 2004 and 2003, 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, 2004. 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, 2004 and 2003
and its distributable income and changes in trust corpus for each of the years in the three-year
period ended December 31, 2004 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, 2004, 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 30, 2005 expressed an unqualified opinion on the trustees assessment of, and
the effective operation of, internal control over financial reporting. /s/ KPMG LLP      

Dallas, Texas
March 30, 2005 32




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BP Prudhoe Bay Royalty
Trust Statement of Assets, Liabilities and Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements) (In thousands, except
unit data) December 31,
    
    
    December 31,2004
    
    
    2003AssetsRoyalty Interest, net (Notes 1, 2 and 3)
    
    $
    12,051
    
    
    $
    14,060Cash and cash equivalents (Note 2)
    
    
    1,001
    
    
    
    986Total Assets
    
    $
    13,052
    
    
    $
    15,046Liabilities and Trust CorpusAccrued expenses
    
    $
    171
    
    
    $
    316Trust Corpus (40,000,000 units of
beneficial interest authorized,
21,400,000 units issued and outstanding
    
    
    12,881
    
    
    
    14,730Total Liabilities and Trust Corpus
    
    $
    13,052
    
    
    $
    15,046
 See accompanying notes to financial statements. 33




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BP Prudhoe Bay Royalty
Trust Statements of Cash Earnings and Distributions
(Prepared on a modified basis of cash receipts and disbursements) (In thousands, except
unit data) December 31,2004
    
    
    2003
    
    
    2002Royalty revenues
    
    $
    82,682
    
    
    $
    55,986
    
    
    $
    33,061Interest income
    
    
    11
    
    
    
    10
    
    
    
    23Less: Trust administrative expenses
    
    
    (976
    )
    
    
    (1,168
    )
    
    
    (822
    )Cash earnings
    
    $
    81,717
    
    
    $
    54,828
    
    
    $
    32,262Cash distributions
    
    $
    81,702
    
    
    $
    54,867
    
    
    $
    32,246Cash distributions per unit
    
    $
    3.818
    
    
    $
    2.564
    
    
    $
    1.507Units outstanding
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
 See accompanying notes to financial statements. 34




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BP Prudhoe Bay Royalty
Trust Statements of Changes in Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements) (In thousands) December 31,2004
    
    
    2003
    
    
    2002Trust Corpus at beginning of year
    
    $
    14,730
    
    
    $
    16,498
    
    
    $
    18,564Cash earnings
    
    
    81,717
    
    
    
    54,828
    
    
    
    32,262Decrease (increase) in accrued expenses
    
    
    145
    
    
    
    279
    
    
    
    (73
    )Cash distributions
    
    
    (81,702
    )
    
    
    (54,867
    )
    
    
    (32,246
    )Amortization of Royalty Interest
    
    
    (2,009
    )
    
    
    (2,008
    )
    
    
    (2,009
    )Trust Corpus at end of year
    
    $
    12,881
    
    
    $
    14,730
    
    
    $
    16,498
 See accompanying notes to financial statements. 35




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BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2004 (1) Formation of the
Trust and Organization BP Prudhoe Bay Royalty Trust (the Trust), a grantor trust, was created as a Delaware business
trust pursuant to a Trust Agreement dated February 28, 1989 among the Standard Oil Company
(Standard Oil), BP Exploration (Alaska) Inc. (the Company), The Bank of New York (The
Trustee) and The Bank of New York (Delaware), as co-trustee. Standard Oil and the Company are
indirect wholly owned subsidiaries of the BP p.l.c. (BP). Effective January 1, 2000, the Company and all other Prudhoe Bay working interest owners
cross-assigned interests in the Prudhoe Bay Field pursuant to the Prudhoe Bay Unit Alignment
Agreement. The Company retained all rights, obligations, and liabilities associated with the
Trust. This transaction is not expected to have a material effect on the Trusts operation. 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
the Companys working interest in the Prudhoe Bay Field (the Field) as of February 28, 1989,
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 the Company of its payment
obligations with respect to the Royalty Interest. 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).
For years subsequent to 2006, Chargeable Costs will be reduced up to a maximum amount of $1.20
per barrel in each year if additions to the Fields proved reserves do not meet certain specific
levels. 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. 36




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BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2004  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 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, 2004, 2003, and 2002 was $0.37. 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. This comprehensive basis of accounting other than generally accepted accounting principles
corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange
Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of
Royalty Trusts. Most accounting pronouncements apply to entities whose financial statements are prepared in
accordance with generally accepted accounting principles, directing such entities to accrue or
defer revenues and expenses in a period other than when such revenues were received or expenses
were paid. Because the Trusts financial statements are prepared on the modified cash basis, as
described above, most accounting pronouncements are not applicable to the Trusts financial
statements. As of December 31, 2004 and 2003, cash equivalents which represent the cash reserve consist of
US 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 37




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BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2004 environment, financial markets and any other parameters used in determining these
estimates could cause actual results to differ, and the difference could be material. (3) Royalty
Interest The Royalty Interest is comprised of the following at December 31, 2004 and 2003 (in thousands): December 31,2004
    
    
    2003Royalty Interest (at inception)
    
    $
    535,000
    
    
    $
    535,000Less: Accumulated amortization
    
    
    (349,431
    )
    
    
    (347,422
    )Impairment write-down
    
    
    (173,518
    )
    
    
    (173,518
    )Balance, end of period
    
    $
    12,051
    
    
    $
    14,060
 (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. 38




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BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2004 (5) Summary of
Quarterly Results (Unaudited) A summary of selected quarterly financial information for the years ended December 31, 2004,
2003, and 2002 is as follows (in thousands, except unit data): 2004 Fiscal QuarterFirst
    
    
    Second
    
    
    Third
    
    
    FourthRoyalty revenues
    
    $
    14,659
    
    
    
    18,342
    
    
    
    21,566
    
    
    
    28,115Interest income
    
    
    2
    
    
    
    3
    
    
    
    2
    
    
    
    4Trust administrative expenses
    
    
    (216
    )
    
    
    (324
    )
    
    
    (212
    )
    
    
    (224
    )Cash earnings
    
    
    14,445
    
    
    
    18,021
    
    
    
    21,356
    
    
    
    27,895Cash distributions
    
    
    14,343
    
    
    
    18,109
    
    
    
    21,352
    
    
    
    27,898Cash distributions per unit
    
    
    0.670
    
    
    
    0.846
    
    
    
    0.998
    
    
    
    1.304
 2003 Fiscal QuarterFirst
    
    
    Second
    
    
    Third
    
    
    FourthRoyalty revenues
    
    $
    12,538
    
    
    
    17,722
    
    
    
    12,147
    
    
    
    13,579Interest income
    
    
    4
    
    
    
    2
    
    
    
    2
    
    
    
    2Trust administrative expenses
    
    
    (469
    )
    
    
    (333
    )
    
    
    (225
    )
    
    
    (141
    )Cash earnings
    
    
    12,073
    
    
    
    17,391
    
    
    
    11,924
    
    
    
    13,440Cash distributions
    
    
    12,412
    
    
    
    17,291
    
    
    
    11,823
    
    
    
    13,341Cash distributions per unit
    
    
    0.580
    
    
    
    0.808
    
    
    
    0.553
    
    
    
    0.623
 2002 Fiscal QuarterFirst
    
    
    Second
    
    
    Third
    
    
    FourthRoyalty revenues
    
    $
    4,841
    
    
    
    5,205
    
    
    
    10,314
    
    
    
    12,701Interest income
    
    
    7
    
    
    
    5
    
    
    
    6
    
    
    
    5Trust administrative expenses
    
    
    (216
    )
    
    
    (298
    )
    
    
    (130
    )
    
    
    (178
    )Cash earnings
    
    
    4,632
    
    
    
    4,912
    
    
    
    10,190
    
    
    
    12,528Cash distributions
    
    
    4,621
    
    
    
    4,931
    
    
    
    10,185
    
    
    
    12,509Cash distributions per unit
    
    
    0.216
    
    
    
    0.230
    
    
    
    0.476
    
    
    
    0.585
 Fiscal Year Ended2004
    
    
    2003
    
    
    2002Royalty revenues
    
    $
    82,682
    
    
    
    55,986
    
    
    
    33,061Interest income
    
    
    11
    
    
    
    10
    
    
    
    23Trust administrative expenses
    
    
    (976
    )
    
    
    (1,168
    )
    
    
    (822
    )Cash earnings
    
    
    81,702
    
    
    
    54,828
    
    
    
    32,262Cash distributions
    
    
    81,702
    
    
    
    54,867
    
    
    
    32,246Cash distributions per unit
    
    
    3.818
    
    
    
    2.564
    
    
    
    1.507
 39




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BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2004  (6)
    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 the Company and
the Trust were based on Company-prepared reserve estimates. The Company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 the Company 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, 2004
($43.46 per barrel), December 31, 2003 ($32.55 per barrel) and December 31, 2002 ($31.23 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. The Royalty Interest includes a provision under which, in years subsequent to 2006, if
additions to the Fields proved reserves from January 1, 1988 (after certain adjustments) do not
meet certain specified levels, Chargeable Costs will be reduced up to a maximum amount of $1.20
per barrel in each year. Under the provisions of FASB 69, no consideration can be given to
reserves not considered proved at the present time. Accordingly, in estimating the reserve
volumes attributable to the Trust, Chargeable Costs were reduced by the maximum amount in years
subsequent to 2006, after considering the amount of reserves that have been added to the Fields
proved reserves from January 1, 1988. Net proved reserves of oil and condensate attributable to the Trust as of December 31, 2004,
2003 and 2002, based on the Companys latest reserve estimate at such time, the WTI Prices on
December 31, 2004, 2003 and 2002, and a reduction in Chargeable Costs in years subsequent to
2006, if reserve additions do not meet specified levels, were estimated to be 77, 78 and 86
million barrels, respectively (of which 68, 67 and 86 million barrels, respectively, are proved
developed). 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 40




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BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2004 may be produced after the currently anticipated end of field life. At December 31,
2004, 2003 and 2002, 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 $43.46, $32.55 and $31.23, respectively, were as
follows (in thousands): December 31,2004
    
    
    2003
    
    
    2002Future net cash flows
    
    $
    1,130,851
    
    
    $
    644,691
    
    
    $
    653,23610% annual discount for
estimated timing of cash flows
    
    
    (454,532
    )
    
    
    (249,373
    )
    
    
    (264,803
    )Standardized measure of discounted future
net cash flow relating to proved reserves
    
    $
    676,319
    
    
    $
    395,318
    
    
    $
    388,433
 The following are the principal sources of the change in the standardized measure of discounted
future net cash flows (in thousands): December 31,2004
    
    
    2003
    
    
    2002Revisions of prior estimates:Reserve volumes
    
    $
    6,123
    
    
    $
    (3,915
    )
    
    $
    90,906WTI price
    
    
    494,363
    
    
    
    56,270
    
    
    
    351,779Adjusted chargeable costs (a)
    
    
    (80,201
    )
    
    
    (15,712
    )
    
    
    (11,116
    )Production taxes
    
    
    (72,641
    )
    
    
    (7,666
    )
    
    
    (52,134
    )Other
    
    
    (15
    )
    
    
    8
    
    
    
    0347,629
    
    
    
    28,985
    
    
    
    379,435Royalty income received (b)
    
    
    (106,160
    )
    
    
    (60,943
    )
    
    
    (42,747
    )Accretion of discount
    
    
    39,532
    
    
    
    38,843
    
    
    
    4,704Net increase (decrease) during the year
    
    $
    281,001
    
    
    $
    6,885
    
    
    $
    341,392
  (a)
    Adjusted chargeable costs are the fixed cost amounts per barrel of royalty production
specified in the Overriding Royalty Conveyance, adjusted for inflation.  (b)
    For the purpose of this calculation, Royalty income received for 2004, 2003 and 2002
includes the following: Period October 1, 2004 through December 31, 2004
    
    $
    33,197Period October 1, 2003 through December 31, 2003
    
    $
    14,659Period October 1, 2002 through December 31, 2002
    
    $
    12,538
 The above royalty income was received by the Trust in January 2005, 2004 and 2003, respectively. 41




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BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2004 The changes in quantities of proved oil and condensate were as follows (in thousands of
barrels): Estimated net proved reserves of oil and condensate at December 31, 2001
    
    
    43,193Production
    
    
    (5,395
    )Reserve estimate revisions
    
    
    Change caused by prices/costs
    
    
    48,020Estimated net proved reserves of oil and condensate at December 31, 2002
    
    
    85,818Production
    
    
    (5,395
    )Reserve estimate revisions
    
    
    (2,481
    )Change caused by prices/costs
    
    
    Estimated net proved reserves of oil and condensate at December 31, 2003
    
    
    77,942Production
    
    
    (5,410
    )Reserve estimate revisions
    
    
    635Change caused by prices/costs
    
    
    4,237Estimated net proved reserves of oil and condensate at December 31, 2004
    
    
    77,404Proved reserves:December 31, 2002
    
    
    85,818December 31, 2003
    
    
    77,942December 31, 2004
    
    
    77,404
 42




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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE There have been no changes in accountants and no disagreements with accountants on any matter
of accounting principles or practices or financial statement disclosures during the two fiscal
years ended December 31, 2004. 
 ITEM 9A. CONTROLS AND PROCEDURES Disclosure Controls and Procedures The Trustee has controls and other procedures that are designed to ensure that information
required to be disclosed by the Trust in the reports that it files or submits under the Securities
Exchange Act of 1934, as amended (the Exchange Act) is recorded processed, summarized and
reported, within the time periods specified in the SECs rules and forms. These controls and
procedures include but are not limited to controls and procedures designed to ensure that
information required to be disclosed by the Trust in the reports that it files or submits under the
Exchange Act is accumulated and communicated to the responsible trust officers of the Trustee to
allow timely decisions regarding required disclosure. As of the end of calendar 2004, the trust officers of the Trustee responsible for the
administration of the Trust conducted an evaluation of the Trusts disclosure controls and
procedures. These officers concluded that the disclosure controls and procedures are effective, but
are subject to certain inherent limitations resulting from the limited powers granted to, and the
limited duties assumed by, the Trustee in the Trust Agreement and the Conveyance, the instruments
which govern the operation of the Trust. The governing instruments give the Trustee no
responsibility for the operation of the Prudhoe Bay Unit or authority over the Company, Standard
Oil or BP. Under the terms of the Conveyance, however, the Company has various disclosure and
reporting obligations, including those summarized below. The Conveyance requires the Company to provide the Trust with the following information and
reports: 1. Such information concerning the Royalty Interest as the Trustee may need and to which
the Company has access to permit the Trust to comply with any reporting or disclosure
obligations of the Trust pursuant to applicable law and the requirements of any stock exchange
on which the Units are issued. 2. A report by February 28 of each year containing all information of a nature, of a
standard and in a form consistent with the requirements of the SEC respecting the inclusion of
reserve and reserve valuation information in filings under the Exchange Act and with applicable
accounting rules. The report is required to set forth, among other things, the Companys
estimates of future net cash flows from proved reserves attributable to the Royalty Interest,
the discounted present value of such proved reserves, the assumptions utilized in arriving at
the estimates contained in the report, and the estimate of the quantities of proved reserves
(including reductions of proved reserves as a result of modification of the Companys estimates
of proved reserves from prior years) added to the total proved reserves allocated to the Subject
Leases as of December 31, 1987 during the preceding year. (See
THE ROYALTY INTEREST 
Chargeable Costs in Item 1.) 3. At least 12 days prior to each Quarterly Record Date, information as to the amount to be
paid to the Trust on the next Quarterly Record Date. 43




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4. A royalty statement within five working days after the end of each calendar quarter
consisting of a computation, supported by data required to perform the computation, of the
amount to be paid to the Trust at the next Quarterly Record Date. In addition, the Conveyance gives the Trust and its independent accountants certain rights to
inspect the books and records of the Company and discuss the affairs, finances and accounts of the
Company relating to the Subject Leases with representatives of the Company; it also requires the
Company to provide the Trust with such other information as the Trustee may reasonably request from
time to time and to which the Company has access. The Trustees disclosure controls and procedures include ensuring that it receives on a timely
basis the information and reports provided by the Company, that the appropriate responsible
personnel of the Trustee examine such information and reports and that information requested from
and provided by the Company is included in the reports that
the Trust files or submits under the Exchange Act. However, the Trustee does not have the means to
evaluate the accuracy or completeness of the information and reports supplied by the Company, nor
does it have the power to ensure that information concerning the Prudhoe Bay Unit and the Subject
Leases that might be considered material by the holders of the Units, but which is not specifically
required by the Conveyance, is supplied to the Trustee by the Company. 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, 2004. The Trustees assessment of the effectiveness of the Trusts internal control over financial
reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public
accounting firm, as stated in their report set forth in full below. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Trustee and Holders of Trust Units of BP Prudhoe Bay Royalty Trust: We have audited the Trustees assessment, included in Trustees Report on Internal Control over
Financial Reporting under Item 9A of the accompanying Annual Report on Form 10-K, that BP Prudhoe
Bay Royalty Trust (the Trust) maintained effective internal control over financial reporting as
of December 31, 2004, based on criteria established in Internal ControlIntegrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of BP
Prudhoe Bay Royalty Trust is responsible for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on the trustees assessment and an opinion on the
effectiveness of the trusts internal control over financial reporting based on our audit. We conducted our audit 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 44




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assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating the trustees assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinion. The Trusts internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with the modified cash basis of accounting. The
Trusts internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with the modified cash basis of accounting, and that receipts and expenditures of the Trust are
being made only in accordance with authorizations of the trustee; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition
of the Trusts assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate. In our opinion, the Trustees assessment that BP Prudhoe Bay Royalty Trust maintained effective
internal control over financial reporting as of December 31, 2004, 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, 2004, 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, 2004 and 2003, 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, 2004,
and our report dated March 30, 2005 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. /s/ KPMG LLP      
Dallas, Texas
March 30, 2005   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. 45




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ITEM 9B. OTHER INFORMATION Not applicable. 
 PART III 
 ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The Trust has no directors or executive officers. The Trustee has only such rights and powers
as are necessary to achieve the purposes of the Trust. 
 ITEM 11. EXECUTIVE COMPENSATION The Trust has no directors, officers or employees to whom it pays compensation. The Trust is
administered by employees of the Trustee in the ordinary course of their employment by the Trustee
and receive no compensation specifically related to their services to the Trust. The compensation received by the Trustee from the Trust during the three fiscal years ended
December 31, 2004 was as follows: Transfer Agentand RegistrarYear ended December 31,
    
    Trustees Fees
    
    Fees2004
    
    $116,378
    
    $6,6472003
    
    114,572
    
    7,3812002
    
    114,572
    
    7,889
 Under the Trust Agreement, the Trustee is entitled to receive on each Quarterly Record Date a
quarterly fee consisting of: (i) a quarterly administrative fee, per Unit outstanding on the
Quarterly Record Date, of $.0011; and (ii) a transfer service fee, per Unit holder account as of
such Quarterly Record Date, of $1.50. Both the administrative service fee and the transfer service
fee are subject to increase for each calendar year commencing after December 31, 1990 by the
proportionate increase, if any, during the preceding calendar year in the Consumer Price Index, as
defined in the Overriding Royalty Conveyance, during the preceding calendar year. Pursuant to the
Trust Agreement, the Trustee also bills the Trust for certain reimbursable expenses. 
 ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Securities Authorized for Issuance under Equity Compensation Plans No Units are authorized for issuance under any form of equity compensation plan. Unit Ownership of Certain Beneficial Owners As of March 30, 2005, there were no persons known to the Trustee to be the beneficial owners
of more than five percent of the Units. 46




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Unit Ownership of Management Neither the Company, 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. 
 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Not applicable. 
 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Fees for services performed by KPMG LLP for the years ended December 31, 2004 and 2003 are: 2004
    
    
    2003Audit
    
    $
    108,000
    
    
    $
    73,000Audit related
    
    
    14,500
    
    
    
    14,500Tax
    
    
    200,000
    
    
    
    200,000Other
    
    
    
    
    
    
    $
    322,500
    
    
    $
    287,500
 The Trust has no audit committee, and as a consequence, has no audit committee pre-approval
policy with respect to fees paid to KPMG LLP. 
 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a) FINANCIAL STATEMENTS The following financial statements of the Trust are included in Part II, Item 8: Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2004 and 2003
Statements of Cash Earnings and Distributions for the years ended
December 31, 2004, 2003 and 2002
Statements of Changes in Trust Corpus for the years ended December 31, 2004, 2003
and 2002
Notes to Financial Statements (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. 47




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(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 among The British Petroleum Company p.l.c.,
BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.31
    
    Rule 13a-14(a) certification.32
    
    Section 1350 certification.
 48




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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 TRUSTBy:
    THE BANK OF NEW YORK, as TrusteeBy:   /s/ Ming J. Ryan
Ming J. Ryan
Vice President March 31, 2005 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. 49




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INDEX TO EXHIBITS  Exhibit No.
    
    Description4.1*
    
    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 among The British Petroleum Company p.l.c.,
BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.31
    
    Rule 13a-14(a) certification. Filed herewith32
    
    Section 1350 certification. Filed herewith.
   *
    
    Incorporated by reference to the correspondingly numbered exhibit to the Registrants
Annual Report on Form 10-K for the fiscal year ended December 31, 1996 (File No. 1-10243). 50