<PAGE>


                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    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, 1999

                                       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
             (Exact name of registrant as specified in its charter)

                DELAWARE                                 13-6943724
      State or other jurisdiction           (I.R.S. Employer Identification No.)
   of incorporation or organization)

     THE BANK OF NEW YORK, TRUSTEE
   101 BARCLAY STREET, FLOOR 21 WEST
           NEW YORK, NEW YORK                              10286
(Address of principal executive offices)                (Zip Code)

       Registrant's telephone number, including area code: (212) 815-5092

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

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

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

         Indicate by check mark 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 [X] No [ ]

         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]

         As of March 28, 2000, 21,400,000 Units of Beneficial Interest were
outstanding. The aggregate market value of Units held by nonaffiliates (based on
the closing sale price on the New York Stock Exchange) was approximately
$219,350,000.

                    Documents Incorporated by Reference: None


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                                TABLE OF CONTENTS

<TABLE>
<S>                                                                                                              <C>
                                     PART I1

ITEM 1.        BUSINESS...........................................................................................1
         INTRODUCTION.............................................................................................1
         THE TRUST................................................................................................2
         THE ROYALTY INTEREST.....................................................................................6
         THE UNITS...............................................................................................12
         THE BP SUPPORT AGREEMENT................................................................................14
         THE PRUDHOE BAY UNIT....................................................................................14
         INDEPENDENT OIL AND GAS CONSULTANTS'REPORT..............................................................20
         INDUSTRY CONDITIONS AND REGULATIONS.....................................................................25
         CERTAIN TAX CONSIDERATIONS..............................................................................25

ITEM 2.        PROPERTIES........................................................................................27

ITEM 3.        LEGAL PROCEEDINGS.................................................................................28

ITEM 4.        SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS...................................................28


                             PART II28

ITEM 5.        MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS..............................................28

ITEM 6.        SELECTED FINANCIAL DATA...........................................................................29

ITEM 7.        TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL
                CONDITION AND RESULTS OF OPERATIONS..............................................................29

ITEM 8.        FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................................................33

ITEM 9.        CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
                ACCOUNTING AND FINANCIAL DISCLOSURE..............................................................44


                             PART III

ITEM 10.       DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................................................44

ITEM 11.       EXECUTIVE COMPENSATION............................................................................44

ITEM 12.       UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                MANAGEMENT.......................................................................................44

ITEM 13.       CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................................................44


                              PART IV

ITEM 14.       EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K..................................44

SIGNATURES.......................................................................................................46

INDEX TO EXHIBITS................................................................................................47
</TABLE>

                                       i

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                                     PART I

ITEM 1   BUSINESS

                                  INTRODUCTION

         BP Prudhoe Bay Royalty Trust (the "Trust"), a grantor trust, was
created as a Delaware business trust pursuant to the BP Prudhoe Bay Royalty
Trust Agreement dated February 28, 1989 (the "Trust Agreement") among The
Standard Oil Company ("Standard Oil"), BP Exploration (Alaska) Inc. (the
"Company"), The Bank of New York, as trustee (the "Trustee"), and F. James
Hutchinson, co-trustee (The Bank of New York (Delaware), successor co-trustee).
The Trustee's corporate trust offices are located at 101 Barclay Street, New
York, New York 10286 and its telephone number is (212) 815-5092. The Company and
Standard Oil are indirect, wholly owned subsidiaries of BP Amoco 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 calculation of the royalty payments
and certain other matters has been furnished to the Trustee by the Company.



                                       1
<PAGE>

                                    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 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 such indebtedness, 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


                                       2
<PAGE>

borrowings are permitted without a vote of holders of Units. 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 for cash the Trust Estate, or a portion
thereof, if such sale is effected in order to provide for the payment of
specific liabilities of the Trust then due and 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 holders of Units. 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. Again, the Trustee must receive an
unqualified written opinion of counsel to the effect that such 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, and the Trustee is obligated to distribute
the available net proceeds of any such sale to the holders of Units 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.

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" Item 1. 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.

                                       3
<PAGE>

         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 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 100 percent of the
holders of 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 80 percent of the holders of 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.


                                       4
<PAGE>

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.

         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


                                       5
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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 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.


                                       6
<PAGE>

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.

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
<PAGE>

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, 1999 were: $8.25
during 1995; $8.50 during 1996; $8.85 during 1997; $9.30 during 1998; and $9.80
during 1999. Chargeable Costs for the calendar year ending December 31, 2000 and
subsequent years are shown in the following table:

               For the       Chargeable        For the      Chargeable
             Year Ending      Costs Per      Year Ending     Costs Per
             December 31       Barrel        December 31      Barrel
             -----------     ----------      -----------    ----------
                 2000          10.00             2011         16.60
                 2001          10.75             2012         16.70
                 2002          11.25             2013         16.80
                 2003          11.75             2014         16.90
                 2004          12.00             2015         17.00
                 2005          12.25             2016         17.10
                 2006          12.50             2017         17.20
                 2007          12.75             2018         20.00
                 2008          13.00             2019         23.75
                 2009          13.25             2020         26.50
                 2010          14.50

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

         Chargeable Costs may be reduced in future years by up to $1.20 per
barrel in the following circumstances:

         (1) Chargeable Costs will be reduced by up to $1.20 per barrel in each
year from 2001 through 2005, inclusive, if, between January 1, 1996 and December
31, 2000, an additional 200,000,000 stock tank barrels ("STB") of proved
reserves (before taking into account any production therefrom) have not been
added to the proved reserves allocated to the Subject Leases. For the purpose of
this calculation, additions to proved reserves include a credit equal to the
number of STB of proved reserves in excess of 100,000,000 added to proved
reserves after December 31, 1987 and before January 1, 1996.

         (2) 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


                                       8
<PAGE>

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.

         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 Reserves
             Year Ended                 ----------------------------
             December 31          Annual                      Cumulative
             -----------          ------                      ----------
                                             (Million STB)
                1988               42.3                          42.3
                1989               45.5                          87.8
                1990               24.0                         111.8
                1991              115.8                         227.6
                1992              144.3                         371.9
                1993              206.2                         578.1
                1994               89.9                         668.0
                1995               92.2                         760.2
                1996              (21.0)                        739.2
                1997               (1.5)                        737.7
                1998               (0.5)                        737.2
                1999                0.0                         737.2

         The Company anticipates that additional drilling, workovers, facilities
modifications, new recovery projects, and programs for production enhancement
and optimization are expected to mitigate, but not eliminate the recent decline
in gross oil and condensate production capacity. As of December 31, 1999, the
cumulative additions to proved reserves allocated to the Subject Leases were
sufficient to prevent any reduction in Chargeable Costs during the years 2001
through 2005. However, significant downward revisions of proved reserve
estimates in 2000 or subsequent years could result in a reduction of Chargeable
Costs being required as described above in the year 2006 or thereafter.

Cost Adjustment Factor

         The "Cost Adjustment Factor" is the ratio of (1) the Consumer Price
Index published for the most recently past February, May, August or November, as
the case may be, to (2) 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,


                                       9
<PAGE>

without seasonal adjustment, by the Bureau of Labor Statistics, Department of
Labor, without regard to subsequent revisions or corrections.

Production Taxes

         "Production Taxes" are the sum of any severance taxes, excise taxes
(including windfall profit tax, if any), sales taxes, value added taxes or other
similar or direct taxes imposed upon the reserves or 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") and the Alaska Oil and Gas
Conservation Tax ("Alaska Conservation 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, and the
Alaska Conservation Tax is a tax of $0.004 per barrel of net production. 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.


                                       10
<PAGE>

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.

<TABLE>
<CAPTION>
                                                         Cost          Adjusted
                     Average WTI      Chargeable      Adjustment      Chargeable      Production       Per Barrel
                        Price           Costs           Factor          Costs            Taxes          Royalty
                     -----------      ----------      ----------      ----------      ----------       ----------
<S>                     <C>              <C>            <C>             <C>              <C>            <C>
1995:
1st Qtr                 18.35            8.25           1.200            9.90            2.00            6.45
2nd Qtr                 19.32            8.25           1.212           10.00            2.11            7.21
3rd Qtr                 17.87            8.25           1.212           10.00            1.90            5.98
4th Qtr                 18.16            8.25           1.217           10.04            1.94            6.18

1996:
1st Qtr                 19.74            8.50           1.227           10.43            2.17            7.14
2nd Qtr                 21.70            8.50           1.241           10.55            2.45            8.70
3rd Qtr                 22.36            8.50           1.247           10.59            2.55            9.22
4th Qtr                 24.71            8.50           1.257           10.68            2.89           11.13

1997:
1st Qtr                 22.86            8.85           1.265           11.19            2.61            9.06
2nd Qtr                 19.91            8.85           1.269           11.23            2.16            6.52
3rd Qtr                 19.75            8.85           1.274           11.28            2.14            6.34
4th Qtr                 19.94            8.85           1.280           11.33            2.16            6.45

1998:
1st Qtr                 15.96            9.30           1.280           11.90            1.56            2.49
2nd Qtr                 14.58            9.30           1.280           11.90            1.36            1.32
3rd Qtr                 14.15            9.30           1.280           11.90            1.29            0.96
4th Qtr                 12.80            9.30           1.280           11.90            1.10            0.00

1999:
1st Qtr                 13.08            9.80           1.280           12.54            1.13            0.00
2nd Qtr                 17.44            9.80           1.280           12.54            1.79            3.11
3rd Qtr                 21.71            9.80           1.287           12.61            2.42            6.68
4th Qtr                 24.60            9.80           1.296           12.70            2.84            9.05
</TABLE>

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


                                       11
<PAGE>

pursuant to the Royalty Interest. This potential conflict of interest could
affect the royalties paid to Unit holders, although the Company will be subject
to the terms of the Prudhoe Bay Unit Operating Agreement.

                                    THE UNITS

Units

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

Distributions of Income

         The Company makes quarterly payments to the Trust of the amounts due
with respect to the Trust's Royalty Interest on the fifteenth day following the
end of each calendar quarter or, if the fifteenth is not a business day, on the
next succeeding business day (the "Quarterly Record Date"). The Trustee, to the
extent possible, pays all expenses of the Trust for each quarter on the
Quarterly Record Date. The Trustee then distributes an amount equal to the
excess, if any, of the cash received by the Trust from the Royalty Interests
over the expenses and payments of liabilities of the Trust, subject to
adjustments for changes made by the Trustee in any cash reserve established for
the payments of estimated liabilities of the Trust (the "Quarterly
Distribution") to the persons in whose names the Units were registered at the
close of business on the immediately preceding Quarterly Record Date.

         The Trust Agreement provides that the Trustee shall pay the Quarterly
Distribution on the fifth day after the Trustee's receipt of the amount paid by
the Company on the Quarterly Record Date, and that collected cash balances being
held by the Trustee for distribution shall be invested in obligations issued or
unconditionally guaranteed by the United States or any agency or instrumentality
thereof and secured by the full faith and credit of the United States
("Government Obligations") or, if Government Obligations with a maturity date on
the date of the distribution to Unit holders are not available, in repurchase
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.


                                       12
<PAGE>

         Following the end of each quarter, the Trustee mails Unit holders a
quarterly report showing the assets and liabilities, receipts and disbursements
and income and expenses of the Trust and the Royalty Production for such
quarter.

Limited Liability of Unit Holders

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

Possible Divestiture of Units

         The Trust Agreement imposes no restrictions on nationality or other
status of the persons eligible to hold Units. However, the Trust Agreement
provides that if at any time the Trust or the Trustee is named a party in any
judicial or administrative proceeding seeking the cancellation or forfeiture of
any property in which the Trust has an interest because of the nationality, or
any other status, of any one or more holders, the following procedures will be
applicable:

                  (i) The Trustee will give written notice of the existence of
         such proceedings to each holder whose nationality or other status is an
         issue in the proceeding. The notice will contain a reasonable summary
         of such proceeding and will constitute a demand to each such holder
         that he dispose of his Units within 30 days to a party not of the
         nationality or other status at issue in the proceeding described in the
         notice.

                  (ii) If any holder fails to dispose of his Units in accordance
         with such notice, the Trustee will redeem, at any time during the
         90-day period following the termination of the 30-day period specified
         in the notice, any Unit not so transferred for a cash price per Unit
         equal to the closing price of the Units on the stock exchange on which
         the Units are then listed or, in the absence of any such listing, the
         closing bid price on the NASDAQ National Market System if the Units are
         so quoted or, if not, the mean between the closing bid and asked prices
         for the Units in the over-the-counter market, in either case as of the
         last business day prior to the expiration of the 30-day period stated
         in the notice. If the Units are neither listed nor traded in the
         over-the-counter market, the price will be the fair market value of the
         Units as determined by a recognized firm of investment bankers or other
         competent advisor or expert.

         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


                                       13
<PAGE>

Company has not conveyed any additional royalty interests to the Trust, and the
Trust has not issued any additional Units, since the inception of the Trust.

                            THE BP SUPPORT AGREEMENT

         BP has agreed pursuant to the terms of a Support Agreement, dated
February 28, 1989, among BP, the Company, Standard Oil and the Trust (the
"Support Agreement"), to provide financial support to the Company in meeting its
payment obligations under the Royalty Interest.

         Within 30 days of notice to BP, BP will ensure that the Company is in a
position to perform its payment obligations under the Royalty Interest and to
satisfy its payment obligations to the Trust under the Trust Agreement,
including contributing to the Company such funds as are necessary to make such
payments. BP's obligations under the Support Agreement are unconditional and
directly enforceable by Unit holders.

         Except as described below, no assignment, sale, transfer, conveyance,
mortgage or pledge or other disposition of the Royalty Interest will relieve BP
of its obligations under the Support Agreement.

         Neither BP nor the Company may transfer or assign its rights or
obligations under the Support Agreement without the prior written consent of the
Trust, except that BP can arrange for its obligations under the Support
Agreement to be performed by any affiliate of BP, provided that BP remains
responsible for ensuring that such obligations are performed in a timely manner.

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

         BP will be released from its obligation under the Support Agreement
upon the sale or transfer of all or substantially all of the Company's working
interest in the Prudhoe Bay Unit if the transferee agrees to assume and be bound
by BP's obligation under the Support Agreement in a writing reasonably
satisfactory to the Trustee and if the transferee is an entity having a rating
assigned to outstanding unsecured, unsupported long term debt from Moody's
Investors Service, Inc. of at least A3 or from Standard & Poor's Ratings Group
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, 1999, approximately 9.9 billion STB of oil and
condensate had been produced from the Field. Field development is well advanced
with approximately $18.0 billion gross capital spent and a


                                       14
<PAGE>

total of about 2,095 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. The Company and a subsidiary of the Atlantic Richfield Company
("Arco") are the two Field operators. Other Field owners include affiliates of
Exxon Mobil Corporation ("Exxon Mobil"), Phillips Petroleum Company ("Phillips")
and Chevron Corporation ("Chevron").

Geology

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

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

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

Oil Characteristics

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

         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. The Company is the operator of the Western Operating Area and
Arco Alaska Inc. is the operator of the Eastern Operating Area. Oil and
condensate production comes from both the Western Operating Area and the Eastern
Operating Area.


                                       15
<PAGE>

         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, 1999 is summarized in the following table:

                                                     Oil Rim         Gas Cap
                                                     -------         -------

         BP.......................................     51.22% (a)     13.83%
         Arco.....................................     21.87          42.56
         Exxon Mobil..............................     23.75          42.84
         Phillips/Chevron.........................      2.55           0.74
         Others...................................      0.60           0.00
                                                      ------         ------
              Total...............................    100.00%        100.00%
                                                      ======         ======
---------------

(a)  The Trust's share of oil production is computed based on BP's
     ownership interest of 50.68 percent as of February 28, 1989.
     Effective December 31, 1995, the Company acquired the
     interest of Amerada Hess Corporation of 0.5379191 percent on
     the oil rim participating area.  Under the terms of the
     Conveyance, this increase in the Company's participation is
     not allocated to the Subject Leases and does not increase 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.

         As of December 31, 1999 there were about 828 active producing oil
wells, 36 gas reinjection wells, 75 water injection wells and 104 water and
miscible gas injection wells in the Field. In terms of individual well
performance, oil production rates range from 100 to 5,500 STB of oil per day.
Currently, the average well production rate is about 660 STB of oil per day.


                                       16
<PAGE>

         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 follow during the periods
indicated:
                                 Oil                     Condensate
               Year        ------------------       -------------------
              Ended        Total      Subject       Total       Subject
           December 31     Field       Leases       Field        Leases
           -----------     -----       ------       -----        ------
                                     (Thousand STB per day)

              1995         659.3       292.4        200.0         24.2
              1996         583.1       258.6        187.6         22.7
              1997         512.8       227.4        177.1         21.4
              1998         442.3       196.1        165.2         20.0
              1999         380.9       170.7        151.5         18.3

         The Company estimates that production will decline at an average rate
of approximately 10 percent per year for the next two to four years, and that
the rate of decline will decrease to approximately five percent per year by the
year 2030.

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 six 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 Company's net proved remaining reserves of oil and condensate in
the Prudhoe Bay Unit as of December 31, 1999 were estimated to be approximately
1,017.7 million STB, of which approximately 1,007.6 million STB were associated
with the Subject Leases. 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 2009. The occurrence of major gas
sales could accelerate the time at which


                                       17
<PAGE>

the Company's net production would fall below 90,000 barrels per day, due to the
consequent decline in reservoir pressure. The Company also projects continued
economic production thereafter, at a declining rate, until the year 2030.

         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, 1999 were 93.6 million barrels of oil and condensate, of
which 89.1 million barrels were proved developed reserves and 4.5 million
barrels were proved undeveloped reserves. Using procedures specified in
Financial Accounting Standards Board Statement of Financial Standards No. 69,
the Company calculated that as of December 31, 1999 production of oil and
condensate from the proved reserves allocated to the Trust will result in
estimated future net revenues to the Trust of $522 million, with a present value
of $305 million. These increases over the corresponding December 31, 1998
figures are a result of the increase in the WTI Price. 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.


                                       18
<PAGE>

         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 Prices
      December 31       Subject Leases (a)       Trust (b)     Per Barrel
      -----------       ------------------       ---------     ----------
                                        (Million STB)

         1995               1,371.4                81.0            19.58
         1996               1,247.0               111.1            25.93
         1997               1,154.7                64.8            17.78
         1998               1,075.4                 0.0            12.05
         1999               1,007.6                93.6            25.60
-------------

(a)  Includes proved undeveloped reserves of 275.2 million STB at December 31,
     1995; 223.4 million STB at December 31, 1996; 190.2 million STB at December
     31, 1997; 109.8 million STB at December 31, 1998; and 108 million STB at
     December 31, 1999.

(b)  Includes proved undeveloped reserves of 0.8 million STB at December 31,
     1995; 9.1 million STB at December 31, 1996; 1.3 million STB at December 31,
     1997; 0.0 STB at December 31, 1998; and 4.5 STB at December 31, 1999.

         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 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.


                                       19
<PAGE>

                   INDEPENDENT OIL AND GAS CONSULTANTS' REPORT


                     [LETTERHEAD OF MILLER AND LENTS, LTD.]




                                February 29, 2000




The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street 21 W
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, 1999

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, 1999. 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 17, 2000 addressed to Mr. Patrick O'Leary of The Bank of New York
and signed by Mr. V. W. Holt. 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


                                       20
<PAGE>

                             MILLER AND LENTS, LTD.

The Bank of New York                                           February 29, 2000
Trustee, BP Prudhoe Bay Royalty Trust


Operating Agreement, the Issues Resolution Agreement, the Overriding Royalty
Conveyance, the Trust Conveyance, the BP Prudhoe Bay Royalty Trust Agreement,
and other related documents referenced in the Form F-3 Registration Statement
filed with the Securities and Exchange Commission on August 7, 1989, by BP
Exploration (Alaska) Inc.

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

         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, 1999, of
                  93.6 million barrels of oil and condensate are, in the
                  aggregate, reasonable. Of the 93.6 million barrels of total
                  Proved Reserves, 89.1


                                       21
<PAGE>

                             MILLER AND LENTS, LTD.

The Bank of New York                                           February 29, 2000
Trustee, BP Prudhoe Bay Royalty Trust


                  million barrels are Proved Developed Reserves, and 4.5 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, 1999, production of the Proved Reserves
                  will result in Estimated Future Net Revenues of $522 million
                  and Present Value of Estimated Future Net Revenues of $305
                  million to the BP Prudhoe Bay Royalty Trust. These estimates
                  are reasonable.

         6.       BP Exploration (Alaska) Inc. estimated that, as of December
                  31, 1999, 737.2 million barrels of Proved Reserves have been
                  added to Current Reserves. This estimate is reasonable.
                  Current Reserves are defined in the Overriding Royalty
                  Conveyance as net Proved Reserves of 2,035.6 million barrels
                  as of December 31, 1987. Net additions to Proved Reserves
                  after December 31, 1987 affect the Chargeable Costs that are
                  used to calculate the Per Barrel Royalty paid to the BP
                  Prudhoe Bay Royalty Trust.

         7.       The BP Exploration (Alaska) Inc. projection that its net
                  production of oil and condensate from Proved Reserves will
                  continue at an average rate exceeding 90,000 barrels per day
                  until the year 2009 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 $25.60 per
                  barrel on December 31, 1999, 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 2017 is reasonable. BP Exploration
                  (Alaska) Inc. expects continued economic production at a
                  declining rate through the year 2030; however, for the
                  economic conditions and production forecast as of December 31,
                  1999, the Per Barrel Royalty will be zero following the year
                  2017. 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.

                                       22
<PAGE>

                             MILLER AND LENTS, LTD.

The Bank of New York                                           February 29, 2000
Trustee, BP Prudhoe Bay Royalty Trust


         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.

         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
2030. 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 determined to be economically viable in the future, BP Exploration
(Alaska) Inc. estimates that such sales would not actually commence until eight
to ten years after such a determination. 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,


                                       23
<PAGE>

                             MILLER AND LENTS, LTD.

The Bank of New York                                           February 29, 2000
Trustee, BP Prudhoe Bay Royalty Trust


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. Koza
                                          Vice President
WPK/hsd





                                       24
<PAGE>

                       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.


                                       25
<PAGE>

     Taxation of Unit Holders

         In computing his federal income tax liability, each Unit holder is
required to take into account his share of all items of Trust income, gain,
loss, deduction, credit and tax preference, based on the Unit holder's method of
accounting. Consequently, it is possible that in any year a Unit holder's share
of the taxable income of the Trust may exceed the cash actually distributed to
him in that year. For example, if the Trustee should 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


                                       26
<PAGE>

business under Internal Revenue Code section 871 or section 882, or pursuant to
any similar provisions of applicable treaties. If a Foreign Taxpayer makes this
election, it is entitled to claim all deductions with respect to such income,
but a United States federal income tax return must be filed to claim such
deductions. This election once made is irrevocable unless an applicable treaty
allows the election to be made annually.

         Section 897 of the Internal Revenue Code and the Treasury Regulations
thereunder treat the Trust as if it were a United States real property holding
corporation. Foreign holders owning more than five percent of the outstanding
Units are subject to United States federal income tax on the gain on the
disposition of their Units. Foreign Unit holders owning less than five percent
of the outstanding Units are 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 872 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.


                                       27
<PAGE>

ITEM 3.  LEGAL PROCEEDINGS

         None.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS

         None.

                                    PART II

ITEM 5.  MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS

         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, 1998 and 1999.

                                                           Distributions
                                  High           Low         Per Unit
                                  ----           ---         --------
         1998:
         First Quarter          $16 7/8        $14 7/16       $0.412
         Second Quarter          14 7/8         10             0.145
         Third Quarter           10 7/8          6 15/16       0.069
         Fourth Quarter           9 1/2          4 5/16        0.055

         1999:
         First Quarter          $ 8 15/16      $ 4 7/16       $0.000(a)
         Second Quarter           8 9/16         5 7/16        0.000(a)
         Third Quarter           11              7 5/16        0.166
         Fourth Quarter          10 15/16        8 1/16        0.404

         As of December 31, 1999, 21,400,000 Units were outstanding and were
held by approximately 975 holders of record.

         (a) Due to the decline in WTI Prices, the Trust did not receive
distributions during the first and second quarters of 1999.

         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.


                                       28
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA

         The following table presents in summary form selected financial
information regarding the Trust.

<TABLE>
<CAPTION>
                                         1999           1998           1997          1996           1995
                                         ----           ----           ----          ----           ----
                                                        (In thousands, except per Unit amounts)
<S>                                      <C>           <C>            <C>           <C>             <C>
 Royalty revenues                       $    13,443        15,163         44,582        42,263          34,886
 Interest income                                 60            17             21             0               0
 Trust administration  expenses                 798           614            845           750             688
 Expenses reserve                               500             0              0             0               0
                                     --------------  ------------   ------------   -----------     -----------
 Cash earnings                          $    12,205        14,566         43,758        41,513          34,198
 Cash distributions                     $    12,205        14,566         43,758        41,513          34,198
 Cash distributions per unit            $     0.570         0.681          2.045         1.940           1.598
 Units outstanding                       21,400,000    21,400,000     21,400,000    21,400,000      21,400,000
</TABLE>

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

                                       29
<PAGE>
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.

         The continued depressed WTI Prices during the fourth quarter of 1998
and first quarter of 1999 resulted in the Trust not receiving distributions
during the first and second quarters of 1999. The Trustee, therefore, determined
to exercise certain of its limited powers under the Trust Agreement to obtain
liquidity in order to meet the Trust's future liabilities and expenses. Given
the unpredictability of WTI Prices and that the Trust only receives quarterly
distributions, the Trustee determined that a cash reserve is necessary to cover
any such future liabilities which may exceed those quarterly distributions
received by drawing upon the cash reserve. The Trustee has received an opinion
of counsel relating to certain tax matters as they pertain to the establishment
of the cash reserve.

         Upon the resumption of distributions in the third quarter of 1999,
attributable to the increase in the WTI Price in the second 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
anticipates setting aside and adding to such cash reserve account, out of any
quarterly distributions received by the Trust, an amount equal to approximately
one year's expected liabilities and expenses of the Trust, which the Trustee
estimates to be approximately $1,000,000. This amount is being set aside over
the course of four quarters, with one quarter of such amount being set aside
each quarter, assuming the availability of funds from quarterly distributions.
The Trustee has set aside $250,000 from the July 15, 1999 distribution, $250,000
from the October 15, 1999 distribution and an additional $250,000 from the
January 15, 2000 distribution for such cash reserve. The Trustee anticipates
that it will be able to bring the cash reserve to a total of approximately
$1,000,000 based on the royalty revenue it anticipates it will receive on April
15, 2000. 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 being invested in U.S.
government or agency securities secured by the full faith and credit of the
United States. The Trustee has determined to distribute any interest received
from the investment to the holders of Units upon maturity on that next 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 are income to the holders of
the Units, (as will be any earning on investment of the cash reserve) and must
be reported by the holders of the Units, even if such amounts are used to repay
borrowings or establish a cash reserve and are not received by the holders of
the Units.

Results of Operations

         Relatively modest changes in oil prices will 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.


                                       30
<PAGE>

         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
the years ended December 31, 1999, 1998 and 1997 are attributable to the
Company's operations during the twelve-month periods ended September 30, 1999,
1998 and 1997, respectively.

         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 2009, 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.

         As a result of the continued decline in the WTI Price during the fourth
quarter of 1998 and the first quarter of 1999 the royalty revenues to the Trust
and cash distributions to the holders of Units declined in 1999. During the
fourth quarter of 1998 and first quarter of 1999 the average daily WTI Price
decreased below the level necessary for the Trust to receive a distribution for
the first and second quarters of 1999. Accordingly, no distribution was made to
holders of Units for such quarters. As a result of the significant increase in
the average daily WTI Price during the second and third quarters of 1999, all
the royalty revenue distributed to the Trust in 1999 and in turn to the holders
of Units was received in the third and fourth quarters of 1999.

         From the latter part of March 1999 up to the time of this report the
WTI Price has 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 fiscal year 2000 depends on WTI Prices prevailing during the
remainder of the year. 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 2009, 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 and changes in the expenses of the Trust.

1998 compared to 1997

         Royalty revenues and cash distributions in 1998 decreased by
approximately 66.0% and 66.7%, respectively, from 1997, as a result of the
progressively decreasing average WTI Prices throughout 1998 (see "THE ROYALTY
INTEREST-Per Barrel Royalty Calculations" in Item 1). Trust administration
expenses decreased by 27.3% from 1997 to 1998, reflecting changes in the timing
of the accounting of such expenses, but, as a percentage of cash earnings,
increased to 4.2% due to the significantly lower cash earnings for the year. The
Royalty Interest for 1998 decreased by approximately 90% from 1997, as a result
of an impairment loss of approximately $174 million, which was calculated as the
difference between the carrying value and the estimated fair value of the
Royalty Interest. The estimated fair value was calculated by projecting future
cash flows and discounting them at a current rate that considered the risk
inherent in the cash flows.


                                       31
<PAGE>

1999 compared to 1998

         Royalty revenues and cash distributions in 1999 decreased by
approximately 11.3% and 16.2%, respectively, from 1998, as a result of the
decline in world oil prices during 1998 and early 1999 (see "THE ROYALTY
INTEREST-Per Barrel Royalty Calculations" in Item 1). Due to an increase in oil
prices starting from the second quarter, the Trust earned all of its royalty
revenue in the third and fourth quarters of 1999. Cash distributions paid to
holders of Units decreased at a greater rate, 16.2%, than royalty revenues,
11.3%, due to the $500,000 contributed to the cash reserve during the
second-half of 1999 and the increase in the payment of Trust administration fees
and expenses. Trust administration expenses increased 30% from 1998 to 1999 and
as a percentage of cash earnings increased to 6.2% from 4.2% in 1998. The
increased dollar amount in the Trustee's expenses was due largely to the fees
and expenses necessary to establish the cash reserve which in conjunction with
the decrease in cash earnings contributed to the increase of Trustee expenses as
a percentage of cash earnings.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
         ABOUT MARKET RISK.

         Not applicable.


                                       32
<PAGE>

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                          BP PRUDHOE BAY ROYALTY TRUST
                          INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                                         Page
                                                                                                         ----

<S>                                                                                                      <C>
Independent Auditors' Report..............................................................................34

Statements of Assets, Liabilities and Trust Corpus As of December 31, 1999 and 1998.......................35

Statement of Cash Earnings and Distributions for the years ended
December 31, 1999, 1998 and 1997..........................................................................36

Statements of Changes in Trust Corpus for the years ended
December 31 1999, 1998 and 1997...........................................................................37

Notes to Financial Statements.............................................................................38
</TABLE>






                                       33
<PAGE>

                          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 as of December 31, 1999 and 1998,
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,
1999. These financial statements are the responsibility of the Trustee. Our
responsibility is to express an opinion on these financial statements based on
our audits.

         We conducted our audits in accordance with generally accepted auditing
standards. 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 have been prepared
on a 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, liabilities and trust corpus of BP
Prudhoe Bay Royalty Trust as of December 31, 1999 and 1998, 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, 1999, on the basis of accounting
described in note 2.


                                    KPMG LLP

New York, New York
February 11, 2000




                                       34
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

               Statements of Assets, Liabilities and Trust Corpus

                           December 31, 1999 and 1998
                        (In thousands, except unit data)



         Assets                                         1999           1998
                                                        ----           ----

Royalty Interest, net (notes 1, 2 and 3)          $     22,596         25,098
Cash                                                       500             13
                                                     ---------     ----------

             Total assets                         $     23,096         25,111
                                                     =========     ==========


         Liabilities and Trust Corpus

Accrued expenses                                  $        470            103
Trust Corpus (40,000,000 units of beneficial
    interest authorized, 21,400,000 units issued
    and outstanding)                                    22,626         25,008

                                                     ---------     ----------

             Total liabilities and Trust Corpus   $     23,096         25,111
                                                     =========     ==========



See accompanying notes to financial statements.



                                       35
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                  Statements of Cash Earnings and Distributions

              For the Years Ended December 31, 1999, 1998 and 1997
                        (In thousands, except unit data)



                                         1999              1998          1997
                                         ----              ----          ----

Royalty revenues                   $      13,443          15,163         44,582

Interest Income                               60              17             21

Trust administrative expenses                798             614            845

Expenses reserve                             500               0              0
                                      ----------      ----------     ----------

Cash earnings                      $      12,205          14,566         43,758
                                      ==========      ==========     ==========

Cash distributions                 $      12,205          14,566         43,758
                                      ==========      ==========     ==========

Cash distributions per unit        $       0.570           0.681          2.045
                                      ==========      ==========     ==========

Units outstanding                     21,400,000      21,400,000     21,400,000
                                      ==========      ==========     ==========


See accompanying notes to financial statements.





                                       36
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                      Statements of Changes in Trust Corpus

              For the Years Ended December 31, 1999, 1998 and 1997
                                 (In thousands)


                                                1999          1998       1997
                                                ----          ----       ----

Trust Corpus at beginning of year          $     25,008     242,829     268,940
Cash earnings                                    12,205      14,566      43,758
 Increase in cash balance                           487          13           0
 (Increase) decrease in accrued expenses           (367)         92        (105)
Cash distributions                              (12,205)    (14,566)    (43,758)
Amortization of Royalty Interest                 (2,502)    (44,408)    (26,006)
Impairment write-down (Note 3)                        0    (173,518)          0
                                             ----------  ----------  ----------

Trust Corpus at end of year                $     22,626      25,008     242,829
                                             ==========  ==========  ==========




See accompanying notes to financial statements.





                                       37
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                          Notes to Financial Statements

                        December 31, 1999, 1998 and 1997

(1)      Formation of the Trust and Organization

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

         During the fourth quarter of 1998, British Petroleum Company p.l.c.
merged with Amoco Corporation to form BP Amoco. This transaction is not expected
to have a material effect on the Trust's operations.

         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") on 16.4246% of 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 by 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
2001, 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.

(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

                                       38
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (continued)

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

         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. As a result of the severe drop in world oil prices during 1998 and
early 1999, the quarterly royalty revenues and cash distributions of the Trust
have been significantly reduced. The royalty revenue for the quarters ended
January 15, 1999 and April 15, 1999 were zero. Due to an increase in oil prices
starting from the second quarter, the Trust has earned royalty revenue since the
second quarter. In order to ensure the Trust has the ability to pay future
expenses, the Trust is establishing a cash reserve account over the next several
quarters sufficient to pay approximately one year's current and expected
liabilities and expenses of the Trust. The Trust has set aside $250,000 to the
cash reserve account each quarter and there was $500,000 in the cash reserve
account as of December 31, 1999.

(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 attributable to the Trust over the production of estimated
     proved reserves attributable to the Trust at the beginning of the fiscal
     year (approximately 0, 65,000,000 and 111,000,000 barrels of estimated
     proved reserves were used to calculate the amortization of the Royalty
     Interest for the years ended December 31, 1999, 1998 and 1997,
     respectively). 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 was $0.47, $8.23 and $4.82 for the years ended
     December 31, 1999, 1998 and 1997, respectively. The Trust evaluates
     impairment of the Royalty Interest by comparing the undiscounted cash flows
     expected to be realized from the Royalty Interest to the carrying value,
     pursuant to Statement of Financial Accounting Standards No. 121 ("SFAS
     121") "Accounting for the Impairment of Long-Lived Assets and for
     Long-Lived Assets to be Disposed Of". 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 (see note 3).

         While these statements differ from financial statements prepared in
accordance with generally accepted accounting principles, the cash basis of
reporting revenues and distributions is considered to be the most meaningful
because quarterly distributions to the Unit holders are based on net cash
receipts.

         The conveyance of the Royalty Interest by Standard Oil to the Trust was
accounted for as a purchase transaction. On February 28, 1989, Standard Oil sold
13,360,000 Trust Units to a group of institutional investors for $334 million in
a private placement. For financial reporting purposes, the Trust's management
valued the remaining Trust Units owned by Standard Oil (8,040,000 units) at a
per unit value equivalent to the amount paid by the investors in the private
placement.

         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.


                                       39
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (continued)

(3)      Royalty Interest

         The Royalty Interest is comprised of the following at December 31, 1999
and 1998 (in thousands):

                                                            1999         1998
                                                            ----         ----

            Royalty
            Interest.................................    $ 535,000      535,000
            Less:  Accumulated amortization..........     (338,886)    (336,384)
                   Impairment write-down............      (173,518)    (173,518)
                                                         ---------     --------

                                                         $  22,596       25,098
                                                         =========     ========

         During the fourth quarter of 1998, the Trust determined that the value
of the Royalty Interest was impaired as a result of the severe drop in world oil
prices during 1998 and reduced the unamortized recorded value by $173,517,532,
to its estimated fair value. The estimated fair value was calculated by
projecting expected future cash flows and discounting them at a current rate
that considered the risk inherent in the cash flows.

(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 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 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.


                                       40
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (continued)

(5)      Summary of Quarterly Results (Unaudited)

         A summary of selected quarterly financial information for the years
ended December 31, 1999 and 1998 is as follows (in thousands, except unit data):

<TABLE>
<CAPTION>
                                                          1st            2nd         3rd           4th
                                                        Quarter        Quarter     Quarter       Quarter
                                                        -------        -------     -------       -------
<S>                                                  <C>              <C>         <C>          <C>
         1999
               Royalty revenues                      $         -            -        4,427        9,016
               Interest income                                 -            -           13           47
               Trust administrative expenses                   -            -         (625)        (173)
               Expense reserve                                 -            -         (250)        (250)
                                                        --------       -------      ------       -------
               Cash earnings                                   -            -        3,565        8,640
               Cash distributions                              -            -        3,565        8,640
               Cash distributions per unit                     -            -        0.166        0.404

         1998
               Royalty revenues                      $     8,773        3,317        1,773        1,300
               Interest income                                 5           12            -            -
               Refund of overpayment of expenses             142            -            -            3
               Trust administrative expenses                (103)        (234)        (303)        (119)
                                                       -----------    --------     -------      -------
               Cash earnings                               8,817        3,095        1,470        1,184
               Cash distributions                          8,817        3,095        1,470        1,184
               Cash distributions per unit                 0.412        0.145        0.069        0.055
</TABLE>

(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, 1999 ($25.60 per barrel), December 31, 1998 ($12.05 per barrel) and
December 31, 1997 ($17.53 per barrel). Because the reserve volumes attributable
to the Trust are estimated using an allocation of reserve volumes based on
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 2001, if additions to
the Field's proved reserves from


                                       41
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (continued)

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, 1999, 1998 and 1997 based on the Company's latest reserve
estimate at such time, the WTI Prices on December 31, 1999, 1998 and 1997 and a
reduction in Chargeable Costs in years subsequent to 1998, were estimated to be
94, 0 and 65 million barrels, respectively (of which 89, 0 and 64 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 increases and the value of additional reserves not considered proved at
the present time or reserves that may be produced after the currently
anticipated end of field life. At December 31, 1999, 1998 and 1997 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 $25.60, $12.05 and
$17.53, respectively, were as follows (in thousands):

                                        December 31,  December 31,  December 31,
                                            1999          1998          1997
                                        ------------  ------------  ------------

   Future net cash flows               $     522,231            0       108,455
   10% annual discount for estimated
     timing of cash flows                   (217,504)           0       (30,649)
                                        ------------   ----------    ----------

   Standardized measure of
     discounted future net cash flow
    relating to proved reserves (a)    $     304,727            0        77,806
                                        ============   ==========    ==========





                                       42
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (continued)

          (a)  The standardized measure of discounted future net cash flow
               relating to proved reserves, estimated without reducing
               Chargeable Costs in years subsequent to 1998, would be $304,727,
               $0 and $69,220 at December 31, 1999, 1998 and 1997, respectively.
               The following are the principal sources of the change in the
               standardized measure of discounted future net cash flows (in
               thousands):

<TABLE>
<CAPTION>
                                                                1999            1998                1997
                                                                ----            ----                ----
<S>                                                           <C>             <C>                <C>
               Revisions of prior estimates:
                  Reserve volumes                             $ 330,031          116,023            33,018
                  WTI price                                           0         (228,764)         (417,392)
                  Chargeable costs - inflation                        0                5           (13,526)
                  Production taxes                                    0           34,319            63,400
                  Other                                               2             (780)           (3,006)
                                                               --------        ----------        ---------
                                                                330,033          (79,197)         (337,506)
               Royalty income received (b)                      (25,306)          (6,390)          (38,218)
               Accretion of discount                                  0            7,781            41,230
                                                               --------        ---------         ---------

               Net increase (decrease) during the year        $ 304,727          (77,806)         (334,494)
                                                               ========        =========         =========

          (b)  Royalty income received for 1999, 1998 and 1997 includes the
               following:
               Period October 1, 1999 through December 31, 1999                                    $12,105
               Period October 1, 1998 through December 31, 1998                                          0
               Period October 1, 1997 through December 31, 1997                                      8,773
               The above royalty income were received by the Trust in January 2000, 1999 and 1998, respectively.

         The changes in quantities of proved oil and condensate were as follows
(thousands of barrels):

                Estimated net proved reserves of oil
                  and condensate at December 31, 1997                                               64,769
                Production                                                                          (5,395)
                Change caused by prices/costs                                                      (59,374)
                                                                                                 ---------
                Estimated net proved reserves of oil
                  and condensate at December 31, 1998                                                    0
                Production                                                                               0
                Change caused by prices/costs                                                       93,582
                                                                                                 ---------
                Estimated net proved reserves of oil
                  and condensate at December 31, 1999                                               93,582
                                                                                                 =========
  Proved reserves:
                    December 31, 1997                                                               64,769
                                                                                                 =========
                    December 31, 1998                                                                    0
                                                                                                 =========
                    December 31, 1999                                                               93,582
                                                                                                 =========
</TABLE>


                                       43
<PAGE>

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

         Not applicable.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

         The Trust has no directors or executive officers. The Trustee has only
such rights and powers as are necessary to achieve the purposes of the Trust.

ITEM 11. EXECUTIVE COMPENSATION

         Not applicable.

ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Unit Ownership of Certain Beneficial Owners

         As of March 28, 2000, 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.

                                    PART IV

ITEM 14. 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


                                       44
<PAGE>

                  as of December 31, 1999 and 1998

                  Statements of Cash Earnings and Distributions for the years
                  ended December 31, 1999, 1998, and 1997

                  Statements of Changes in Trust Corpus for the years
                  ended December 31, 1999, 1998, and 1997

                  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.

27       Financial Data Schedule

(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, 1999.



                                       45
<PAGE>

                                   SIGNATURES

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

                                           BP PRUDHOE BAY ROYALTY TRUST

                                           By:  THE BANK OF NEW YORK, as Trustee


                                           By: /s/ Marie Trimboli
                                              ------------------------
                                              Marie Trimboli
                                              Assistant Treasurer

March 29, 2000


         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.




                                       46
<PAGE>

                                INDEX TO EXHIBITS


Exhibit No.                        Description
-----------                        -----------

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.

27       Financial Data Schedule. Filed herewith.


--------------------------------------------
         * Incorporated by reference to the correspondingly numbered exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year ended December
31, 1996 (File No. 1-10243).