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UNITED STATES SECURITIES AND EXCHANGE COMMISSION  FORM 10-K (X)
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the Fiscal Year ended December 31, 2003 OR (   )
    
    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
(   ) No (X) 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. (X) Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes (X) No
(   ) The aggregate market value of Units held by nonaffiliates (computed by
reference to the closing sale price in New York Stock Exchange Composite
Transactions on June 30, 2003 (the last business day of the registrants most
recently completed second fiscal quarter) was approximately $404,246,000. As of March 24, 2004, 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
    
    
    23CERTAIN TAX CONSIDERATIONS
    
    
    23ITEM 2.
    
    PROPERTIES
    
    
    25ITEM 3.
    
    LEGAL PROCEEDINGS
    
    
    25ITEM 4.
    
    SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS
    
    
    25PART II
    
    
    
    
    26ITEM 5.
    
    MARKET FOR THE UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS
    
    
    26ITEM 6.
    
    SELECTED FINANCIAL DATA
    
    
    27ITEM 7.
    
    TRUSTEES DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
    
    
    27ITEM 7A.
    
    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
    
    
    29ITEM 8.
    
    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
    
    
    30ITEM 9.
    
    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
    
    
    42ITEM 9A.
    
    CONTROLS AND PROCEDURES
    
    
    42PART III
    
    
    
    
    42ITEM 10.
    
    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
    
    
    42ITEM 11.
    
    EXECUTIVE COMPENSATION
    
    
    42ITEM 12.
    
    UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
    
    
    43
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ITEM 13.
    
    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
    
    
    43ITEM 14.
    
    PRINCIPAL ACCOUNTANT FEES AND SERVICES
    
    
    43ITEM 15.
    
    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
    
    
    44SIGNATURES
    
    
    45EX-31  CertificationEX-32 Certification
  ii




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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 Barrels* 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




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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 additional information. 
 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 pursuant to an Overriding
Royalty Conveyance dated February 27, 1989 between the Company and Standard Oil
and a Trust Conveyance dated February 28, 1989 between Standard Oil and 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 Securities and Exchange Commission 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 Contingent Reserves 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. As discussed above, the Trustee may establish a cash reserve for the
payment of material liabilities of the Trust which may become due, if the
Trustee has determined that it is not practical to pay such liabilities out of
funds anticipated to be available for subsequent quarterly distributions and
that, in the absence of such a reserve, the trust estate is subject to the risk
of loss or diminution in value or The Bank of New York is subject to the risk
of personal liability for such liabilities. 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 previously described, certain
other necessary conditions must also be satisfied prior to the establishment of
a cash reserve or the Trusts borrowing of funds. 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, 2003, 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 2018. 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, 2003 were: $9.80 during 1999;
$10.00 during 2000; $10.75 during 2001; $11.25 during 2002; and $11.75 during
2003. Chargeable Costs for the calendar year ending December 31, 2004 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 Barrel2004
    
    $
    12.00
    
    
    
    2013
    
    
    $
    16.802005
    
    
    12.25
    
    
    
    2014
    
    
    
    16.902006
    
    
    12.50
    
    
    
    2015
    
    
    
    17.002007
    
    
    12.75
    
    
    
    2016
    
    
    
    17.102008
    
    
    13.00
    
    
    
    2017
    
    
    
    17.202009
    
    
    13.25
    
    
    
    2018
    
    
    
    20.002010
    
    
    14.50
    
    
    
    2019
    
    
    
    23.752011
    
    
    16.60
    
    
    
    2020
    
    
    
    26.502012
    
    
    16.70
 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
    
    
    42.3
    
    
    
    42.31989
    
    
    45.5
    
    
    
    87.81990
    
    
    24.0
    
    
    
    111.81991
    
    
    115.8
    
    
    
    227.61992
    
    
    144.3
    
    
    
    371.91993
    
    
    206.2
    
    
    
    578.11994
    
    
    89.9
    
    
    
    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
    
    
    
    815.0
 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. 9




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##### Table of Contents



Production Taxes Production Taxes are the sum of any severance taxes, excise taxes
(including windfall profit tax, if any), sales taxes, value added taxes or
other similar or direct taxes imposed upon the reserves or production, delivery
or sale of Royalty Production. 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. The Per Barrel Royalty with respect to
each calendar quarter is paid to the Trust on the fifteenth day of the month
following the end of the quarter. See THE UNITS - Distributions of Income
below. Cost
    
    AdjustedAverage
    
    Chargeable
    
    Adjustment
    
    Chargeable
    
    Production
    
    Per BarrelWTI Price
    
    Costs
    
    Factor
    
    Costs
    
    Taxes
    
    Royalty1999:1st Qtr
    
    $
    13.08
    
    
    $
    9.80
    
    
    
    1.280
    
    
    $
    12.54
    
    
    $
    1.13
    
    
    $
    0.002nd Qtr
    
    
    17.44
    
    
    
    9.80
    
    
    
    1.280
    
    
    
    12.54
    
    
    
    1.79
    
    
    
    3.113rd Qtr
    
    
    21.71
    
    
    
    9.80
    
    
    
    1.287
    
    
    
    12.61
    
    
    
    2.42
    
    
    
    6.684th Qtr
    
    
    24.60
    
    
    
    9.80
    
    
    
    1.296
    
    
    
    12.70
    
    
    
    2.84
    
    
    
    9.052000:1st 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
    
    
    
    3.56
 10




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##### Table of Contents



Cost
    
    AdjustedAverage
    
    Chargeable
    
    Adjustment
    
    Chargeable
    
    Production
    
    Per BarrelWTI Price
    
    Costs
    
    Factor
    
    Costs
    
    Taxes
    
    Royalty2002:1st 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
 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. 11




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##### Table of Contents



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 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 12




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##### Table of Contents



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. 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 13




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##### Table of Contents



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). 
 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, 2003, approximately 10.6
billion STB of oil and condensate had been produced from the Field. Field
development is well advanced with approximately $18.5 billion gross capital
spent and a total of about 2,109 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. Since several oil companies hold acreage within the Field, the Prudhoe Bay
Unit was established to optimize Field development. The Prudhoe Bay Unit
Operating Agreement specifies the allocation of production and costs to Prudhoe
Bay Unit owners. Prior to July 1, 2000, the Company and a subsidiary of the
Atlantic Richfield Company were the two Field operators. On July 1, 2000,
following the acquisition by BP of Atlantic Richfield Company, the Company
assumed sole-operatorship of the field. Other Field owners include affiliates
of Exxon Mobil Corporation (Exxon Mobil), ConocoPhillips, ChevronTexaco
Corporation and Forest Oil Corporation. 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. 14




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##### Table of Contents



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. 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 companies hold acreage within the Fields limits, a unit was
established to ensure optimum development of the Field. 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. 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, the Company assumed sole
operatorship 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, 2003 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 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. 15




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##### Table of Contents



As of December 31, 2003 there were about 1,109 active producing oil wells,
33 gas reinjection wells, 80 water injection wells and 137 water and miscible
gas injection wells in the Field. In terms of individual well performance, oil
production rates range from 100 to 3,500 STB of oil per day. Currently, the
average well production rate is about 350 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 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)1999
    
    
    380.9
    
    
    
    170.7
    
    
    
    151.5
    
    
    
    18.32000
    
    
    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
    
    
    
    13.8
 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 to Valdez where it is either loaded onto marine tankers or
stored temporarily. It takes the oil about seven days to make the trip in the
48-inch diameter pipeline. 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 858.7 million STB as of December 31, 2003.
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 16




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reservoir pressure. The Company also projects continued economic
production thereafter, at a declining rate, until the year 2035; however, for
the economic conditions and production forecast as of December 31, 2003, it is
estimated that royalty payments will cease following the year 2018. 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 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, 2003 were 77.94 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, 2003
production of oil and condensate from the proved reserves allocated to the
Trust will result in estimated future net revenues to the Trust of $644.7
million, with a present value of $395.3 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)1999
    
    
    1,007.6
    
    
    
    93.6
    
    
    $
    25.602000
    
    
    999.6
    
    
    
    90.7
    
    
    
    26.832001
    
    
    961.7
    
    
    
    43.2
    
    
    
    19.782002
    
    
    908.7
    
    
    
    85.8
    
    
    
    31.232003
    
    
    858.7
    
    
    
    77.9
    
    
    
    32.55
  (a)
    
    Includes proved undeveloped reserves of 108 million STB at December
31, 1999; 137.3 million STB at December 31, 2000; 112.5 million STB at
December 31, 2001; 5.5 million STB at December 31, 2002; and 139.9
million STB at December 31, 2003. 17




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(b)
    
    Includes proved undeveloped reserves of 4.5 million STB at December
31, 1999; 6.4 million STB at December 31, 2000; 0.03 million STB at
December 31, 2002; and 11.0 STB at December 31, 2003. 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 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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##### Table of Contents



INDEPENDENT OIL AND GAS CONSULTANTS REPORT MILLER AND LENTS, LTD.
INTERNATIONAL OIL AND GAS CONSULTANTS
TWENTY-SEVENTH FLOOR
1100 LOUISIANA
HOUSTON, TEXAS 77002-5216
TELEPHONE 713 651-9455
TELEFAX 713 654-9914
email: mail@millerandlents.com February 12, 2004 The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street, 8 West
New York, New York 10286 Re:
    
    Estimates of Proved Reserves,
Future Production Rates, and
Future Net Revenues for the BP
Prudhoe Bay Royalty Trust As of
December 31, 2003
 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, 2003. 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 10, 2004 addressed to Ms. Marie E. Trimboli 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 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 19




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##### Table of Contents



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, 2003, of 77.94
million barrels of oil and condensate are, in the aggregate,
reasonable. Of the 77.94 million barrels of total Proved Reserves,
66.94 million barrels are Proved Developed Reserves, and 11.0
million barrels are Proved Undeveloped Reserves.5.
    
    Utilizing the specified procedures outlined in Financial
Accounting Standards Board Statement of Financial Accounting
Standards No. 69, BP Exploration (Alaska) Inc. calculated that as of
December 31, 2003 production of the Proved Reserves will result in
Estimated Future Net Revenues of $644.7 million and Present Value of
Estimated Future Net Revenues of $395.3 million to the BP Prudhoe
Bay Royalty Trust. These estimates are reasonable.6.
    
    BP Exploration (Alaska) Inc. estimated that, as of December
31, 2003, 815.0 million barrels of Proved Reserves have been added
to Current Reserves. This estimate is 20




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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 $32.55 per
barrel on December 31, 2003, 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 2018 is reasonable. BP Exploration (Alaska) Inc.
expects continued economic production at a declining rate through
the year 2035; however, for the economic conditions and production
forecast as of December 31, 2003 the Per Barrel Royalty will be zero
following the year 2018. Therefore, no reserves are currently
attributed to the BP Prudhoe Bay Royalty Trust after that date.9.
    
    Even if expected reservoir performance does not change, the
estimated reserves, economic life, and future revenues attributable
to the BP Prudhoe Bay Royalty Trust may change significantly in the
future. This may result from changes in the West Texas Intermediate
Price or from changes in other prescribed variables utilized in
calculations defined by the Overriding Royalty Conveyance. Estimates of ultimate and remaining reserves and production scheduling
depend upon assumptions regarding expansion or implementation of alternative
projects or development programs and upon strategies for production
optimization. BP Exploration (Alaska) Inc. has continual reservoir management,
surveillance, and planning efforts dedicated to (1) gathering new information,
(2) improving the accuracy of its reserves and production capacity estimates,
(3) recognizing and exploiting new opportunities, (4) anticipating potential
problems and taking corrective actions, and (5) identifying, selecting, and
implementing optimum recovery program and cost reduction alternatives. Given
this significant effort and ever-changing economic conditions, estimates of
reserves and production profiles will change periodically. The current estimate of Proved Reserves includes only those projects or
development programs that are deemed reasonably certain to be implemented,
given current economic and regulatory conditions. Future projects, development
programs, or operating strategies different from those assumed in the current
estimates may change future estimates and affect recoveries. However, because
several complementary and alternative projects are being considered for
recovery of the remaining oil in the 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. 21




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##### Table of Contents



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 2035.
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. 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, LTD.By
    
    /s/ William P. Koza                      [SEAL]William P. KozaVice President
 WPK/hsd 22




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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 23




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##### Table of Contents



taxable income of the Trust may exceed the cash actually distributed to
him in that year. For example, if 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 24




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##### Table of Contents



percent of the outstanding Units are subject to United States federal
income tax on the gain on the disposition of their Units. Foreign Unit holders
owning less than five percent of the outstanding Units are not subject to
United States federal income tax on the gain on the disposition of their Units,
unless they have elected under Internal Revenue Code section 871 or section 882
to treat the income from the Royalty Interest as effectively connected with the
conduct of a United States trade or business. If a Foreign 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 31 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 UNIT HOLDERS No matters were submitted to a vote of Unit holders during the fourth
quarter ended December 31, 2003. 25




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##### Table of Contents



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, 2003. DistributionsHigh
    
    Low
    
    Per Unit2002:First Quarter
    
    $
    15.01
    
    
    $
    10.98
    
    
    $
    0.216Second Quarter
    
    
    14.37
    
    
    
    11.20
    
    
    
    0.230Third Quarter
    
    
    14.49
    
    
    
    10.70
    
    
    
    0.476Fourth Quarter
    
    
    15.10
    
    
    
    12.50
    
    
    
    0.5852003: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
    
    
    
    0.623
 As of March 24, 2004, 21,400,000 Units were outstanding and were held by
913 holders of record. No Units were purchased by the Trust or any affiliated
purchaser during the year ended December 31, 2003. 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. 26




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##### Table of Contents



ITEM 6. SELECTED FINANCIAL DATA The following table presents in summary form selected financial
information regarding the Trust. 2003
    
    2002
    
    2001
    
    2000
    
    1999(in thousands, except per Unit amounts)Royalty revenues
    
    $
    55,986
    
    
    
    33,061
    
    
    
    59,934
    
    
    
    65,026
    
    
    
    13,443Interest income
    
    $
    10
    
    
    
    23
    
    
    
    70
    
    
    
    92
    
    
    
    60Trust administration expenses
    
    $
    1,168
    
    
    
    822
    
    
    
    724
    
    
    
    732
    
    
    
    798Expenses reserve
    
    $
    
    
    
    
    
    
    
    
    
    
    
    
    500
    
    
    
    500Cash earnings
    
    $
    54,828
    
    
    
    32,262
    
    
    
    59,280
    
    
    
    63,886
    
    
    
    12,205Cash distributions
    
    $
    54,867
    
    
    
    32,246
    
    
    
    59,319
    
    
    
    63,838
    
    
    
    12,205Cash distributions per unit
    
    $
    2.564
    
    
    
    1.507
    
    
    
    2.772
    
    
    
    2.983
    
    
    
    0.570Units outstanding
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
 
 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. 27




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The decline in WTI Prices during the fourth quarter of 1998 and the first
quarter of 1999 resulted in the Trust not receiving quarterly distributions
during the first and second quarters of 1999. See THE ROYALTY INTEREST  Per
Barrel Royalty Calculations. Upon the increase in the WTI Price in the second
quarter of 1999 and the resumption of distributions in the third quarter of
1999, the Trustee established a cash reserve to provide liquidity to the Trust
during any future periods in which the Trust does not receive a distribution.
The Trustee set aside $1,000,000 in the cash reserve account, from quarterly
distributions received by the Trust, in four equal quarterly installments
commencing with the July 1999 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. 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. The Trustee anticipates
that it will keep this cash reserve program in place until termination of the
Trust. 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 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 year 2003 and the period of 2004 up to the date of this report,
the 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 2004 will depend on WTI Prices prevailing during the
remainder of the year. 28




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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. 2002 compared to 2001 Royalty revenues and cash distributions in calendar 2002 decreased by
approximately 44.8% and 45.6%, respectively, from 2001. The decline was due
principally to a sharp drop in average WTI Prices during the fourth quarter of
2001 and the first quarter of 2002. Although WTI prices recovered later in 2002
to approximately the same levels as at the beginning of 2001, overall the
average WTI Price for the twelve months ended September 30, 2002 (on which
calendar 2002 cash basis revenues were based) was approximately 16% lower than
for the immediately preceding twelve-month period. Royalty revenues also were
negatively affected by the scheduled increase in Chargeable Costs from $10.75
to $11.25 in the first quarter of 2002; however this impact was somewhat offset
by Production Taxes, which declined approximately 21% during the twelve-month
period ended September 30, 2002 from the preceding period as a consequence of
the decreases in average WTI Prices. The Cost Adjustment Factor had a neutral
effect during 2002, as it remained substantially constant on average from the
previous year. 
 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 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. 29




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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Bp Prudhoe Bay Royalty
Trust Index To Financial
Statements PageIndependent Auditors Report
    
    
    31Statements of Assets, Liabilities and Trust Corpus as of December 31, 2003 and 2002
    
    
    32Statements of Cash Earnings and Distributions for the years ended
December 31, 2003, 2002 and 2001
    
    
    33Statements of Changes in Trust Corpus for the years ended
December 31 2003, 2002 and 2001
    
    
    34Notes to Financial Statements
    
    
    35
 30




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Independent
Auditors Report 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, 2003
and 2002, and the related statements of cash earnings and distributions, and
changes in trust corpus for each of the years in the three-year period ended
December 31, 2003. 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 auditing standards generally
accepted in the United States of America. 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, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. As described in Note 2, these financial statements were prepared on the
modified basis of cash receipts and disbursements, which is a comprehensive
basis of accounting other than generally accepted accounting principles. In our opinion, the financial statements referred to above present fairly, in
all material respects, the assets and liabilities and trust corpus of BP
Prudhoe Bay Royalty Trust as of December 31, 2003 and 2002, and its cash
earnings and distributions and its changes in trust corpus for each of the
years in the three-year period ended December 31, 2003, on the basis of
accounting described in Note 2. KPMG LLP New York, New York
March 4, 2004 31




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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 31,2003
    
    2002AssetsRoyalty Interest, net (Notes 1, 2 and 3)
    
    $
    14,060
    
    
    $
    16,068Cash and cash equivalents (Note 2)
    
    
    986
    
    
    
    1,025Total Assets
    
    $
    15,046
    
    
    $
    17,093Liabilities and Trust CorpusAccrued expenses
    
    $
    316
    
    
    $
    595Trust Corpus (40,000,000 units of
beneficial interest authorized,
21,400,000 units issued and outstanding
    
    
    14,730
    
    
    
    16,498Total Liabilities and Trust Corpus
    
    $
    15,046
    
    
    $
    17,093
 See accompanying notes to financial statements. 32




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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 31,2003
    
    2002
    
    2001Royalty revenues
    
    $
    55,986
    
    
    $
    33,061
    
    
    $
    59,934Interest income
    
    
    10
    
    
    
    23
    
    
    
    70Less: Trust administrative expenses
    
    
    (1,168
    )
    
    
    (822
    )
    
    
    (724
    )Cash earnings
    
    $
    54,828
    
    
    $
    32,262
    
    
    $
    59,280Cash distributions
    
    $
    54,867
    
    
    $
    32,246
    
    
    $
    59,319Cash distributions per unit
    
    $
    2.564
    
    
    $
    1.507
    
    
    $
    2.772Units outstanding
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
 See accompanying notes to financial statements. 33




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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 31,2003
    
    2002
    
    2001Trust Corpus at beginning of year
    
    $
    16,498
    
    
    $
    18,564
    
    
    $
    20,669Cash earnings
    
    
    54,828
    
    
    
    32,262
    
    
    
    59,280Decrease (increase) in accrued expenses
    
    
    279
    
    
    
    (73
    )
    
    
    (58
    )Cash distributions
    
    
    (54,867
    )
    
    
    (32,246
    )
    
    
    (59,319
    )Amortization of Royalty Interest
    
    
    (2,008
    )
    
    
    (2,009
    )
    
    
    (2,008
    )Trust Corpus at end of year
    
    $
    14,730
    
    
    $
    16,498
    
    
    $
    18,564
 See accompanying notes to financial statements. 34




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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, 2003  (1)
    
    Formation of the Trust and OrganizationBP 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. 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, 2003  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.
    
    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, 2003, 2002, and 2001 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.  While these statements differ from financial statements prepared in
accordance with accounting principles generally accepted in the United
States of America, the modified cash basis of reporting revenues and
distributions is considered to be the most meaningful because quarterly
distributions to the Trust Unit Holders are based on net cash receipts. The
accompanying modified cash basis financial statements contain all
adjustments necessary to present fairly the assets, liabilities and Corpus
of the Trust as of December 31, 2003 and 2002, and the modified cash earning
and distributions and changes in Trust Corpus for the years ended December
31, 2003, 2002 and 2001. The adjustments are of a normal recurring nature
and are, in the opinion of the Trustee, necessary to fairly present the
results of operations.As of December 31, 2003 and 2002, 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 environment,
financial markets and any other parameters used in determining these
estimates could cause actual results to differ, and the difference could be
material. 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, 2003  Certain reclassifications have been made to prior year financial statements
to conform to the 2003 presentation.  (3)
    
    Royalty Interest  The Royalty Interest is comprised of the following at December 31, 2003 and 2002 (in thousands): December 31,2003
    
    2002Royalty Interest (at inception)
    
    $
    535,000
    
    
    $
    535,000Less: Accumulated amortization
    
    
    (347,422
    )
    
    
    (345,414
    )Impairment write-down
    
    
    (173,518
    )
    
    
    (173,518
    )Balance, end of period
    
    $
    14,060
    
    
    $
    16,068
  (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. 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, 2003  (5)
    
    Summary of Quarterly Results (Unaudited)  A summary of selected quarterly financial information for the years ended
December 31, 2003, 2002, and 2001 is as follows (in thousands, except unit
data): 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
 2001 Fiscal QuarterFirst
    
    Second
    
    Third
    
    FourthRoyalty revenues
    
    $
    19,932
    
    
    
    14,418
    
    
    
    13,269
    
    
    
    12,315Interest income
    
    
    19
    
    
    
    17
    
    
    
    23
    
    
    
    11Trust administrative expenses
    
    
    (158
    )
    
    
    (253
    )
    
    
    (269
    )
    
    
    (44
    )Cash earnings
    
    
    19,793
    
    
    
    14,182
    
    
    
    13,023
    
    
    
    12,282Cash distributions
    
    
    19,777
    
    
    
    14,167
    
    
    
    13,096
    
    
    
    12,279Cash distributions per unit
    
    
    0.924
    
    
    
    0.662
    
    
    
    0.612
    
    
    
    0.574
 Fiscal Year Ended2003
    
    2002
    
    2001Royalty revenues
    
    $
    55,986
    
    
    
    33,061
    
    
    
    59,934Interest income
    
    
    10
    
    
    
    23
    
    
    
    70Trust administrative expenses
    
    
    (1,168
    )
    
    
    (822
    )
    
    
    (724
    )Cash earnings
    
    
    54,828
    
    
    
    32,262
    
    
    
    59,280Cash distributions
    
    
    54,867
    
    
    
    32,246
    
    
    
    59,319Cash distributions per unit
    
    
    2.564
    
    
    
    1.507
    
    
    
    2.772
 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, 2003  (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, 2003 ($32.55 per barrel), December 31, 2002 ($31.23
per barrel), and December 31, 2001 ($19.78 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 1998, 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, 2003, 2002, and 2001, based on the Companys latest reserve
estimate at such time, the WTI Prices on December 31, 2003, 2002, and 2001
and a reduction in Chargeable Costs in years subsequent to 1998, were
estimated to be 78, 86, and 43 million barrels, respectively (of which 67,
86, and 43 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 39




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##### Table of Contents



BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2003  may be produced after the currently anticipated end of field life. At
December 31, 2003, 2002, and 2001, 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 $32.55, $31.23, and $19.78, respectively, were as
follows (in thousands): December 31,2003
    
    2002
    
    2001Future net cash flows
    
    $
    644,691
    
    
    $
    653,236
    
    
    $
    64,58410% annual discount for
estimated timing of cash flows
    
    
    (249,373
    )
    
    
    (264,803
    )
    
    
    (17,543
    )Standardized measure of discounted future
net cash flow relating to proved reserves
    
    $
    395,318
    
    
    $
    388,433
    
    
    $
    47,041
  The following are the principal sources of the change in the standardized
measure of discounted future net cash flows (in thousands): December 31,2003
    
    2002
    
    2001Revisions of prior estimates:Reserve volumes
    
    $
    (3,915
    )
    
    $
    90,906
    
    
    $
    47,566WTI price
    
    
    56,270
    
    
    
    351,779
    
    
    
    (314,605
    )Chargeable
costs - inflation
    
    
    (15,712
    )
    
    
    (11,116
    )
    
    
    (24,460
    )Production taxes
    
    
    (7,666
    )
    
    
    (52,134
    )
    
    
    48,033Other
    
    
    8
    
    
    
    0
    
    
    
    66728,985
    
    
    
    379,435
    
    
    
    (242,799
    )Royalty income received (b)
    
    
    (60,943
    )
    
    
    (42,747
    )
    
    
    (47,032
    )Accretion of discount
    
    
    38,843
    
    
    
    4,704
    
    
    
    30,625Net increase (decrease) during the year
    
    $
    6,885
    
    
    $
    341,392
    
    
    $
    (259,206
    )
  (b)
    
    For the purpose of this calculation, Royalty income received for
2003, 2002, and 2001 includes the following: Period October 1, 2003 through December 31, 2003
    
    $
    14,659Period October 1, 2002 through December 31, 2002
    
    $
    12,538Period October 1, 2001 through December 31, 2001
    
    $
    4,841
  The above royalty income was received by the Trust in January 2004, 2003,
and 2002, respectively.  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
    )
 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, 2003 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
    
    
    77,942Proved reserves:December 31, 2001
    
    
    43,193December 31, 2002
    
    
    85,818December 31, 2003
    
    
    77,942
 41




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##### Table of Contents



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, 2003. 
 ITEM 9A. CONTROLS AND PROCEDURES As of the end of the period covered by this report, the Trustee carried
out an evaluation of the effectiveness of the design and operation of the
Trusts disclosure controls and procedures pursuant to Exchange Act Rule 13a-15
and 15d-15. Based upon that evaluation, the Trustee concluded that the Trusts
disclosure controls and procedures are effective in timely alerting the Trustee
to material information relating to the Trust required to be included in the
Trusts periodic filings with the SEC. In its evaluation of disclosure controls
and procedures, the Trustee has relied, to the extent considered reasonable, on
information provided by BP Exploration (Alaska) Inc. There has not been any
change in the Trusts internal control over financial reporting that has
materially affected, or is reasonably likely to materially affect, the Trusts
internal control over financial reporting. 
 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, 2003 was as follows: Transfer Agentand RegistrarYear ended December 31,
    
    Trustees Fees
    
    Fees2003
    
    $
    114,572
    
    
    $
    7,3812002
    
    
    114,572
    
    
    
    7,8892001
    
    
    114,572
    
    
    
    6,827
 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 $0.0011; 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. 42




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##### Table of Contents



ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED UNITHOLDER MATTERS
 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 24, 2004, there were no persons known to the Trustee to be the
beneficial owners of more than five percent of the Units. 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,
2003 and 2002 are: 2003
    
    2002Audit
    
    $
    73,000
    
    
    $
    61,760Audit related
    
    
    14,500
    
    
    
    14,500Tax
    
    
    200,000
    
    
    
    180,000Other
    
    
    
    
    
    
    $
    287,500
    
    
    $
    256,260
 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. 43




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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) FINANCIAL STATEMENTS The following financial statements of the Trust are included in Part II,
Item 8:  Independent Auditors Report
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2003 and 2002
Statements of Cash Earnings and Distributions for the years ended December 31, 2003, 2002 and 2001
Statements of Changes in Trust Corpus for the years ended December 31, 2003, 2002 and 2001
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. (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. (d) REPORTS ON FORM 8-K No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the quarter ended December 31, 2003. 44




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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. RyanMing J. RyanVice President
 March 25, 2004 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. 45




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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.
    46