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, 2002

                                       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
         NEW YORK, NEW YORK                                10286
(Address of principal executive offices)                 (Zip Code)

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

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

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

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

     Indicate by check mark  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  27,  2003,  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
$120,482,000.

     Documents Incorporated by Reference: None

<PAGE>

                                TABLE OF CONTENTS

PART I.........................................................................1

   ITEM 1.  BUSINESS...........................................................1
             INTRODUCTION......................................................1
             THE TRUST.........................................................2
             THE ROYALTY INTEREST..............................................7
             THE UNITS........................................................11
             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........................................................28
   ITEM 3.  LEGAL PROCEEDINGS.................................................28
   ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS...................28

PART II.......................................................................29

   ITEM 5.  MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS..............29
   ITEM 6.  SELECTED FINANCIAL DATA...........................................29
   ITEM 7.  TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
              AND RESULTS OF OPERATIONS.......................................30
   ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........32
   ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................32
   ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
              AND FINANCIAL DISCLOSURE........................................44

PART III......................................................................44

   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
   ITEM 14. CONTROLS AND PROCEDURES...........................................44

PART IV.......................................................................45

   ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K..45

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


                                       i
<PAGE>

                                     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) 815-896-6908.  The Company and Standard Oil are wholly
owned subsidiaries of BP p.l.c. ("BP").

     Upon  creation of the Trust,  the Company  conveyed  to Standard  Oil,  and
Standard Oil, in turn, conveyed to the Trust an overriding royalty interest (the
"Royalty Interest"), which entitles the Trust to a royalty on 16.4246 percent of
the first 90,000  Barrels* of the average actual daily net production of oil and
condensate  per quarter from the working  interest of the Company as of February
28, 1989 in the Prudhoe Bay Unit  located on the North Slope in Alaska (see "THE
PRUDHOE BAY UNIT" below).  The Royalty  Interest is free of any  exploration and
development expenditures.

     The only assets of the Trust are the Royalty Interest assigned to the Trust
and cash or cash  equivalents  held by the Trustee from time to time as reserves
or for distribution (the "Trust Estate"). The Trust is a passive entity, and the
Trustee has been given only such powers as are necessary for the  collection and
distribution  of  revenues  from the Royalty  Interest  and the payment of Trust
liabilities and expenses.  The beneficial  interest in the Trust is divided into
equal  undivided  units (the  "Units").  The Units are not an  interest in or an
obligation  of the Company,  Standard Oil or BP. The Delaware  Trust Act,  under
which the Trust was formed, entitles holders of the Units to the same limitation
of personal liability as stockholders of a Delaware corporation.

     The Company  shares  control of the  operation of the Prudhoe Bay Unit with
other  working  interest  owners.  The  operations  of the Company and the other
working  interest  owners are governed by an agreement dated April 1, 1977 among
the State of Alaska and such working  interest owners  establishing  the Prudhoe
Bay Unit (the "Prudhoe Bay Unit Agreement") and an agreement dated April 1, 1977
among the working  interest  owners  governing  Prudhoe Bay Unit operations (the
"Prudhoe  Bay Unit  Operating  Agreement").  The  Company has no  obligation  to
continue  production from the Prudhoe Bay Unit or to maintain  production at any
level and may interrupt or discontinue  production at any time. The operation of
the  Prudhoe  Bay Unit is subject to normal  operating  hazards  incident to the
production and  transportation  of oil in Alaska.  In the event of damage to the
Prudhoe Bay Unit which is covered by insurance, the Company has no obligation to
use  insurance  proceeds  to repair  such  damage  and may elect to retain  such
proceeds and close damaged areas to production.

----------
     * As used in the overriding  royalty  conveyance  and this report,  (a) the
term "Barrel" is a unit of measure equal to 42 United States  gallons  corrected
to 60 degrees Fahrenheit  temperature and with deductionf for sediment and water
content,  and (b) the term  "Stock Tank  Barrel" or "STB"  refers to a Barrel of
stabilized  oil or  condensate  at a temperature  of 60 degrees  Fahrenheit  and
sea-level atmospheric pressure (14.7 pounds per square inch absolute).


                                       1
<PAGE>

     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.

                                    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


                                       2
<PAGE>

opinion of counsel to the effect that such borrowing  will not adversely  affect
the  classification  of the Trust as a "grantor  trust" for  federal  income tax
purposes or cause the income from the Trust to be treated as unrelated  business
taxable income for federal  income tax purposes  unless the Trustee is unable to
obtain such  opinion and  determines  that the failure to effect such  borrowing
will be materially  detrimental  to the Unit Holders  considered as a whole.  To
secure  payment  of  borrowings  by the Trust,  the  Trustee  is  authorized  to
mortgage,  pledge,  grant security  interests in or otherwise encumber the Trust
Estate or any portion thereof  (including the Royalty Interest) and to carve out
and convey  production  payments.  The borrowing itself and the pledges or other
encumbrances to secure  borrowings are permitted without a vote of Unit holders.
In the event of such  borrowings,  no further  Trust  distributions  may be made
until the indebtedness created by such borrowings has been paid in full.

     The Trustee may sell Trust properties only as authorized by the affirmative
vote of the holders of Units  representing 70 percent of the Units  outstanding,
provided,  however,  that if such sale is  effected  in order to provide for the
payment of specific  liabilities  of the Trust then due and involves a part, but
not all or substantially  all, of the Trust Estate,  such sale shall be approved
by the affirmative vote of a majority of the holders of the Units.

     The Trustee may also sell the Trust Estate, or a portion thereof,  for cash
if such  sale is  effected  in order to  provide  for the  payment  of  specific
liabilities of the Trust then due, cash on hand is insufficient  and the Trustee
is unable to effect a borrowing by the Trust.  The Trustee  must also  determine
that the failure to pay such liabilities at a later date will be contrary to the
best interest of the holders of Units and that it is not  practicable  to submit
the sale to a vote of the Unit  holders.  The sale must be  effected  at a price
which (in the opinion of an investment  banking firm or commercial banking firm)
is at least equal to the fair market value of the interest  sold and is effected
pursuant to  commercially  reasonable  terms when  compared  to other  available
alternatives. The Trustee must receive an unqualified written opinion of counsel
to the effect that the sale will not adversely affect the  classification of the
Trust as a "grantor  trust" for federal  income tax purposes or cause the income
from the Trust to be treated as unrelated  business  taxable  income for federal
income tax  purposes  unless the  Trustee is unable to obtain  such  opinion and
determines  that the failure to effect such sale will be materially  detrimental
to the Unit Holders  considered  as a whole.  Finally,  the Trustee may sell the
Trust Estate upon termination of the Trust.

     Any sale of Trust properties must be for cash unless  otherwise  authorized
by the holders of Units.  The Trustee is obligated to  distribute  the available
net proceeds of any such sale to the Unit holders  after  establishing  reserves
for liabilities of the Trust.

         Except  in  certain  circumstances,  the  Trustee  is  entitled  to  be
indemnified  out of the assets of the Trust for any liability,  expense,  claim,
damage or other loss incurred by it in the performance of its duties unless such
loss  results  from its  negligence,  bad faith or fraud or from its expenses in
carrying out such duties  exceeding the  compensation  and  reimbursement  it is
entitled to under the Trust Agreement.

Employees
---------

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



                                       3
<PAGE>

Property of the Trust
---------------------

     Except for cash and cash equivalents held by the Trustee from time to time,
the property of the Trust  consists  exclusively  of the Royalty  Interest.  The
Royalty  Interest was conveyed to the Trust  pursuant to an  Overriding  Royalty
Conveyance  dated  February  27, 1989 between the Company and Standard Oil and a
Trust Conveyance dated February 28, 1989 between Standard Oil and the Trust. The
Overriding   Royalty  Conveyance  and  the  Trust  Conveyance  are  referred  to
collectively  herein as the  "Conveyance." For a description of the terms of the
Royalty Interest,  see "THE ROYALTY INTEREST" below. The discussion of the terms
of the  Conveyance  herein is  qualified  in its  entirety by  reference  to the
relevant   provisions  of  the  Overriding  Royalty  Conveyance  and  the  Trust
Conveyance  which are filed  with the  Securities  and  Exchange  Commission  as
exhibits to this report.

     The  interest  conveyed  to the Trust by the  Conveyance  is an  overriding
royalty  interest  consisting  of the right to receive a Per Barrel  Royalty for
each  Barrel of Royalty  Production.  The  meaning of these  terms is more fully
described below under "THE ROYALTY  INTEREST." The Trust does not have the right
to take oil and gas in kind.

     The Royalty Interest  constitutes a  non-operational  interest in minerals.
The  Trust  has no right to take over  operations  or to share in any  operating
decision  whatsoever  with  respect to the  Company's  working  interest  in the
Prudhoe Bay Unit.  The Company is not  obligated to continue to operate any well
or  maintain in force or attempt to maintain in force any portion of its working
interest in the Prudhoe Bay Unit when, in its  reasonable  and prudent  business
judgment such well or interest  ceases to produce or is not capable of producing
oil or gas in paying quantities.

     Under the terms of the Prudhoe Bay Unit Operating Agreement, if the Company
fails to pay any costs and expenses  chargeable to the Company under the Prudhoe
Bay  Unit  Operating  Agreement  and the  production  of oil and  condensate  is
insufficient to pay such costs and expenses,  the Royalty Interest is chargeable
with a pro rata  portion  of such  costs  and  expenses  and is  subject  to the
enforcement  against it of liens  granted to the  operators  of the  Prudhoe Bay
Unit.  However, in the Conveyance the Company agreed to pay timely all costs and
expenses  chargeable to it and to ensure that no such costs and expenses will be
chargeable  against  the  Royalty  Interest.  The  Trust is not  liable  for any
expense,  claim,  damage,  loss or  liability  incurred by the Company or others
attributable to the Company's working interest in the Prudhoe Bay Unit or to the
oil produced from it, and the Company has agreed to indemnify the Trust and hold
it harmless against any such impositions.

     The  Company  has the  right to amend or  terminate  the  Prudhoe  Bay Unit
Agreement,   the  Prudhoe  Bay  Unit  Operating  Agreement  and  any  leases  or
conveyances  with  respect  to  its  working  interest  in the  exercise  of its
reasonable and prudent  business  judgment  without  liability to the Trust. The
Company  also has the  right to sell or  assign  all or any part of its  working
interest in the Prudhoe Bay Unit, so long as the sale or assignment is expressly
made  subject  to the  Royalty  Interest  and the  terms and  provisions  of the
Conveyance.



                                       4
<PAGE>

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 holders of 100 percent
of  the  outstanding  Units  and  by  the  Trustee,   or  reduce  or  delay  the
distributions  to the holders of Units or effect  certain other  changes  unless
approved  by the  affirmative  vote of  holders  of at least 80  percent  of the
outstanding  Units and by the Trustee.  No amendment will be effective until the
Trustee has received a ruling from the Internal Revenue Service or an opinion of
counsel to the  effect  that such  modification  will not  adversely  affect the
classification of the Trust as a "grantor trust" for federal income tax purposes
or cause the income from the Trust to be treated as unrelated  business  taxable
income for federal income tax purposes.

Resignation or Removal of Trustee
---------------------------------

     The Trustee may resign at any time or be removed  with or without  cause by
the holders of a majority of the  outstanding  Units.  Its  successor  must be a
corporation  organized and doing  business  under the laws of the United States,
any state  thereof or the  District of Columbia,  authorized  under such laws to
exercise trust powers, or a national banking association domiciled in the United
States, in either case having a combined capital,  surplus and undivided profits
of at least  $50,000,000 and subject to supervision or examination by federal or
state authorities.  Unless the Trust already has a trustee that is a resident of
or has a principal office in the State of Delaware,  then any successor  trustee
will be such a resident  or have such a  principal  office.  No  resignation  or
removal of the Trustee shall become  effective  until a successor  trustee shall
have accepted appointment.

Liabilities and Contingent Reserves
-----------------------------------

     Because of the passive nature of the Trust's assets and the restrictions on
the power of the Trustee to incur obligations,  the only liabilities incurred by
the Trust are routine  administrative  expenses,  such as  Trustee's  fees,  and
accounting, legal and other professional fees.

     As  discussed  above,  the  Trustee may  establish  a cash  reserve for the
payment  of  material  liabilities  of the Trust  which may become  due,  if the
Trustee has determined  that it is not practical to pay such  liabilities out of
funds  anticipated to be available for subsequent  quarterly  distributions  and
that, in the absence of such a reserve,  the trust estate is subject to the risk
of loss or diminution in value or The Bank of New York is subject to the risk of
personal  liability  for such  liabilities.  The Trustee is  obligated to borrow
funds  required  to pay  liabilities  of the Trust  when  due,  and to pledge or
otherwise encumber the Trust's assets, if it determines that the cash on hand is
insufficient  to pay such  liabilities  and that it is not practical to pay such
liabilities  out of funds  anticipated to be available for subsequent  quarterly
distributions.   Borrowings   must  be  repaid  in  full   before  any   further
distributions  are made to holders of Units.  As previously  described,  certain
other necessary  conditions must also be satisfied prior to the establishment of
a cash reserve or the Trust's borrowing of funds.



                                       5
<PAGE>

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 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.



                                       6
<PAGE>

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.

Royalty Production
------------------

     The  "Royalty  Production"  for each day in a  calendar  quarter is 16.4246
percent of the first 90,000  Barrels of the actual  average daily net production
of oil and  condensate  for such quarter  from the Prudhoe Bay  (Permo-Triassic)
Reservoir  and  allocated  to the oil and gas leases owned by the Company in the
Prudhoe  Bay Unit as of  February  28,  1989 or as  modified  thereafter  by any
redetermination  provided  under the  terms of the  Prudhoe  Bay Unit  Operating
Agreement and the Prudhoe Bay Unit Agreement (the "Subject Leases"). The Royalty
Production  is based on oil produced  from the oil rim and  condensate  produced
from the gas cap, but not on gas  production or natural gas liquids  production.
The actual average daily net  production of oil and condensate  from the Subject
Leases for any calendar  quarter is the total  production of oil and  condensate
for such quarter,  net of the State of Alaska royalty,  divided by the number of
days in such quarter.

Per Barrel Royalty
------------------

     The "Per Barrel  Royalty"  in effect for any day is an amount  equal to the
WTI Price for such day less the sum of (i) the product of the  Chargeable  Costs
multiplied by the Cost Adjustment Factor and (ii) Production Taxes. Based on the
WTI Price on December 31, 2002,  current  Production  Taxes and Chargeable Costs
adjusted in  accordance  with the  Conveyance,  the Company  estimates  that Per
Barrel Royalty payments will continue through the year 2018.



                                       7
<PAGE>

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.

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, 2002 were:  $9.30 during 1998;
$9.80 during 1999;  $10.00 during 2000;  $10.75  during 2001;  and $11.25 during
2002.  Chargeable  Costs for the  calendar  year  ending  December  31, 2003 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
      -----------          ------       -----------           ------
         2003             $ 11.75           2012            $ 16.70
         2004               12.00           2013              16.80
         2005               12.25           2014              16.90
         2006               12.50           2015              17.00
         2007               12.75           2016              17.10
         2008               13.00           2017              17.20
         2009               13.25           2018              20.00
         2010               14.50           2019              23.75
         2011               16.60           2020              26.50

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

     Chargeable  Costs  will be  reduced  by up to $1.20 per  Barrel in 2006 and
subsequent  years if, between January 1, 2001 and December 31, 2005,  either (a)
an additional 400,000,000 STB of proved reserves (before taking into account any
production  therefrom) have not been added to proved  reserves  allocated to the
Subject Leases (including,  for the purpose of this calculation,  a credit equal
to the number of STB of proved  reserves in excess of  300,000,000  added to the


                                       8
<PAGE>

Company's  reserves after December 31, 1987 and before January 1, 2001),  or (b)
an additional 100,000,000 STB of proved reserves (before taking into account any
production  therefrom)  have not been  added to the  reserves  allocated  to the
Subject  Leases,  without  allowing any credit for additions prior to January 1,
2001. In general,  "proved reserves" for purposes of this determination  consist
of the Company's estimate (determined to be reasonable by independent  petroleum
engineers) of the  quantities of crude oil and  condensate  that  geological and
engineering  data  demonstrate  with  reasonable  certainty to be recoverable in
future years under existing  economic and operating  conditions from the Prudhoe
Bay  (Permo-Triassic  Reservoir)  in the Prudhoe Bay Unit.  See "THE PRUDHOE BAY
UNIT - Reserve Estimates" below.

     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
        2000                          57.3                 794.5
        2001                          20.5                 815.0
        2002                           0.0                 815.0

     Additional  drilling,  workovers,  facilities  modifications,  new recovery
projects and programs for production  enhancement and optimization may mitigate,
but not  eliminate  the recent  decline in gross oil and  condensate  production
capacity.  However,  significant  downward revisions of proved reserve estimates
could  result in a reduction  of  Chargeable  Costs being  required as described
above in the year 2006 and thereafter.

Cost Adjustment Factor
----------------------

     The "Cost  Adjustment  Factor" is the ratio of (i) the Consumer Price Index
published for the most recently past February,  May, August or November,  as the
case may be, to (ii) 121.1 (the Consumer Price Index for January  1989),  except
that (a) if for any  calendar  quarter  the average WTI Price is $18.00 or less,
then the Cost  Adjustment  Factor for that quarter  will be the Cost  Adjustment
Factor for the immediately preceding quarter, and (b) the Cost Adjustment Factor
for any calendar quarter in which the average WTI Price exceeds $18.00,  after a
calendar  quarter  during which the average WTI Price is equal to or less than $
18.00, and for each following calendar quarter in which the average WTI Price is
greater than $18.00,  will be the product of (x) the Cost Adjustment  Factor for
the most recently past calendar  quarter in which the average WTI Price is equal
to or less than $18.00 and (y) a fraction,  the  numerator  of which will be the


                                       9
<PAGE>

Consumer Price Index published for the most recently past February,  May, August
or  November,  as the  case may be,  and the  denominator  of which  will be the
Consumer Price Index published for the most recently past February,  May, August
or November  during a quarter in which the average WTI Price is equal to or less
than $18.00.  The "Consumer Price Index" is the U.S.  Consumer Price Index,  all
items and all urban consumers,  U.S. city average,  1982-84 equals 100, as first
published,  without  seasonal  adjustment,  by the  Bureau of Labor  Statistics,
Department of Labor, without regard to subsequent revisions or corrections.

Production Taxes
----------------

     "Production  Taxes"  are  the  sum of any  severance  taxes,  excise  taxes
(including windfall profit tax, if any), sales taxes, value added taxes or other
similar or direct taxes  imposed upon the  reserves or  production,  delivery or
sale of Royalty Production.  Such taxes are computed at defined statutory rates.
In the case of taxes based upon wellhead or field value, the Conveyance provides
that the WTI Price less the product of $4.50 and the Cost Adjustment factor will
be deemed to be the wellhead or field value. At the present time, the Production
Taxes payable with respect to the Royalty  Production are the Alaska Oil and Gas
Properties  Production Tax ("Alaska  Production  Tax").  For the purposes of the
Royalty  Interest,  the Alaska  Production Tax is computed without regard to the
"economic  limit  factor," if any, as the  greater of the  "percentage  of value
amount"  (based on the statutory  rate and the wellhead  value as defined above)
and the "cents per Barrel amount." As of the date of this report,  the statutory
rate for the  purpose of  calculating  the  "percentage  of value  amount" is 15
percent. A surcharge to the Alaska Production Tax increased  Production Taxes by
$0.05 per Barrel of net  production  effective  July 1,  1989.  Due to the spill
response  fund  reaching $50 million in 1995,  $0.02 per Barrel of the surcharge
has been indefinitely  suspended. In the event the balance of the spill response
fund falls below $50 million,  the $0.02 per Barrel surcharge will be reinstated
until the fund balance again reaches $50 million. The remaining $0.03 per Barrel
surcharge is not affected by the fund's  balance and will continue to be imposed
at all times.

Per Barrel Royalty Calculations

     The following table shows how the above-described factors interacted during
each of the past five years to produce the Per Barrel  Royalty  paid for each of
the calendar  quarters  indicated.  The Per Barrel  Royalty with respect to each
calendar  quarter  is  paid  to the  Trust  on the  fifteenth  day of the  month
following  the end of the  quarter.  See "THE UNITS -  Distributions  of Income"
below.
<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>
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>


                                       10
<PAGE>

<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>
2000:
 1st Qtr             $28.86          $10.00         1.307            $13.07          $3.48           $12.31
 2nd Qtr              28.87           10.00         1.319             13.19           3.47            12.21
 3rd Qtr              31.63           10.00         1.330             13.30           3.88            14.45
 4th Qtr              31.98           10.00         1.341             13.41           3.92            14.66

2001:
 1st Qtr              28.83           10.75         1.354             14.55           3.44            10.84
 2nd Qtr              27.92           10.75         1.368             14.71           3.29             9.92
 3rd Qtr              26.82           10.75         1.367             14.69           3.13             9.00
 4th Qtr              20.41           10.75         1.366             14.68           2.17             3.56

2002:
 1st Qtr              21.67           11.25         1.369             15.40           2.36             3.91
 2nd Qtr              26.28           11.25         1.384             15.57           3.04             7.67
 3rd Qtr              28.33           11.25         1.391             15.65           3.34             9.34
 4th Qtr              28.25           11.25         1.396             15.70           3.33             9.22
</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
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.



                                       11
<PAGE>

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.

     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.



                                       12
<PAGE>

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 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.



                                       13
<PAGE>

                            THE BP SUPPORT AGREEMENT

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

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

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

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

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

     BP will be released from its  obligation  under the Support  Agreement upon
the  sale or  transfer  of all or  substantially  all of the  Company's  working
interest in the Prudhoe Bay Unit if the transferee agrees to assume and be bound
by  BP's  obligation  under  the  Support  Agreement  in  a  writing  reasonably
satisfactory  to the Trustee and if the  transferee is an entity having a rating
assigned  to  outstanding  unsecured,  unsupported  long term debt from  Moody's
Investors Service,  Inc. of at least A3 or from Standard & Poor's of at least A-
or an  equivalent  rating  from at least one  nationally-recognized  statistical
rating  organization (after giving effect to the sale or transfer to such entity
of all or substantially all of the Company's working interest in the Prudhoe Bay
Unit and the assumption by such entity of all of the Company's obligations under
the Conveyance and of all BP's obligations under the Support Agreement).

                              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, 2002,  approximately  10.5 billion STB of oil
and  condensate  had been produced  from the Field.  Field  development  is well
advanced  with  approximately  $18.3  billion gross capital spent and a total of
about 2,051 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.



                                       14
<PAGE>

     Since several oil companies hold acreage within the Field,  the Prudhoe Bay
Unit was  established  to  optimize  Field  development.  The  Prudhoe  Bay Unit
Operating  Agreement specifies the allocation of production and costs to Prudhoe
Bay Unit  owners.  Prior to July 1, 2000,  the Company and a  subsidiary  of the
Atlantic  Richfield  Company  were the two  Field  operators.  On July 1,  2000,
following  the  acquisition  by BP of Atlantic  Richfield  Company,  the Company
assumed sole-operatorship of the field. Other Field owners include affiliates of
Exxon  Mobil  Corporation  ("Exxon  Mobil"),  ConocoPhillips  and  ChevronTexaco
Corporation.

Geology
-------

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

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

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

Oil Characteristics
-------------------

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

     The  interests of the Unit holders are based upon oil produced from the oil
rim and condensate produced from the gas cap, but not upon gas production (which
is currently  uneconomic)  or natural gas liquids  production  stripped from gas
produced.

Prudhoe Bay Unit Operation and Ownership
----------------------------------------

     Since several  companies hold acreage within the Field's limits, a unit was
established  to ensure optimum  development of the Field.  The Prudhoe Bay Unit,
which became  effective on April 1, 1977,  divided the Field into two  operating
areas.  Prior to July 1, 2000,  the  Company  was the  operator  of the  Western
Operating  Area and Arco Alaska Inc. was the  operator of the Eastern  Operating


                                       15
<PAGE>

Area. Oil and condensate  production  came from both the Western  Operating Area
and the  Eastern  Operating  Area.  On July 1, 2000,  the Company  assumed  sole
operatorship of the field.

     The  Prudhoe Bay Unit  Operating  Agreement  specifies  the  allocation  of
production  and costs to the  working  interest  owners.  The  Prudhoe  Bay Unit
Operating   Agreement  also  defines   operator   responsibilities   and  voting
requirements and is unusual in its establishment of separate participating areas
for the gas cap and oil rim.

     The ownership of the Prudhoe Bay Unit by participating  area as of December
31, 2002 is summarized in the following table:

                                 Oil Rim Gas Cap

     BP....................................... 26.35% (a)           26.35% (b)
     Exxon Mobil.............................. 36.40                36.40
     ConocoPhillips........................... 36.07                36.07
     Others...................................  1.18                 1.18
                                              ------               ------
         Total................................100.00%              100.00%
                                              ======               ======
---------------

(a)  The Trust's  share of oil  production is computed  based on BP's  ownership
     interest  on the oil rim area of 50.68  percent as of  February  28,  1989.
     Subsequent  decreases in the Company's  participation were not allocated to
     the Subject Leases and have not decreased the Trust's Royalty Interest.

(b)  The  Trust's  share of  condensate  production  is  computed  based on BP's
     ownership  interest on the oil rim area of 13.84 percent as of February 28,
     1989.  Subsequent  increases  in  the  Company's   participation  were  not
     allocated to the Subject Leases and have not increased the Trust's  Royalty
     Interest.

Historical Production
---------------------

     Production  began on June 19, 1977, with the completion of the Trans Alaska
Pipeline System. The pipeline has a capacity of approximately 1.4 million STB of
oil per day.

     As of December 31, 2002 there were about 1,111 active  producing oil wells,
33 gas  reinjection  wells,  68 water injection wells and 143 water and miscible
gas injection wells in the Field. In terms of individual well  performance,  oil
production  rates  range  from 100 to 3,500 STB of oil per day.  Currently,  the
average well production rate is about 375 STB of oil per day.

     The Company's  share of the hydrocarbon  liquids  production from the Field
includes  oil,  condensate  and  natural  gas  liquids.   Using  the  production
allocation procedures from the Prudhoe Bay Unit Operating Agreement, the Field's
production and the share of oil and condensate  (net of State of Alaska royalty)
allocated  to the  Subject  Leases  have  been as  follows  during  the  periods
indicated:



                                       16
<PAGE>

                         Oil                        Condensate
       Year       ------------------           --------------------
      Ended       Total      Subject           Total        Subject
   December 31    Field       Leases           Field         Leases
   -----------    -----       ------           -----         ------
                               (Thousand STB per day)

      1998        442.3        196.1           165.2          20.0
      1999        380.9        170.7           151.5          18.3
      2000        364.0        161.4           146.7          17.8
      2001        324.9        144.1           131.2          15.9
      2002        293.8        130.3           121.5          14.7

Transportation of Prudhoe Bay Oil
---------------------------------

     Production  from the  Field is  carried  to Pump  Station  1,  which is the
starting  point  for the Trans  Alaska  Pipeline  System,  through  two  34-inch
diameter  transit  lines,  one from each half of the Field.  At Pump  Station 1,
Alyeska  Pipeline  Service Company,  the pipeline  operator,  meters the oil and
pumps it south to Valdez where it is either loaded onto marine tankers or stored
temporarily.  It takes the oil about  seven days to make the trip in the 48-inch
diameter pipeline.

Reservoir Management
--------------------

     The  Prudhoe  Bay Field is a  complex,  combination-drive  reservoir,  with
widely varying reservoir  properties.  Reservoir  management  involves directing
Field activities and projects to maximize the economic value of Field reserves.

     Several  different  oil recovery  mechanisms  are  currently  active in the
Field, including pressure depletion,  gravity drainage/gas cap expansion,  water
flooding and miscible gas flooding. Separate yet integrated reservoir management
strategies  have been developed for the areas affected by each of these recovery
processes.

Reserve Estimates
-----------------

     The net proved remaining reserves of oil and condensate associated with the
Subject Leases is approximately  908.7 million STB as of December 31, 2002. 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 2016.  The  occurrence  of major gas sales could
accelerate  the time at which the  Company's  net  production  would  fall below
90,000 Barrels per day, due to the consequent decline in reservoir pressure. The
Company also projects continued economic production  thereafter,  at a declining
rate, until the year 2030;  however,  for the economic conditions and production
forecast as of December 31, 2002,  it is estimated  that royalty  payments  will
cease following the year 2018.



                                       17
<PAGE>

     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,  2002 were  85.82  million  Barrels of oil and  condensate.  Using
procedures  specified  in  Financial  Accounting  Standards  Board  Statement of
Financial  Standards No. 69, the Company calculated that as of December 31, 2002
production of oil and condensate from the proved reserves allocated to the Trust
will result in  estimated  future net  revenues to the Trust of $653.2  million,
with a present  value of  $388.4  million.  The  Company's  estimates  of proved
reserves and the  estimated  future net revenues  from the Prudhoe Bay Unit have
been reviewed by Miller and Lents, Ltd., independent oil and gas consultants, as
set forth in their report following this section.

     There is no precise method of forecasting the allocation of reserve volumes
between  the  Company  and the  Trust.  The  Royalty  Interest  is not a working
interest  and the  Trust is not  entitled  to  receive  any  specific  volume of
reserves from the Field.  Rather,  reserve volumes  attributable to the Trust at
any given date are  estimated by  allocating to the Trust its share of estimated
future  production  from  the  Field  based on WTI  Prices  and  other  economic
parameters in effect on the date of the evaluation.

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

                           Net Proved Reserves
                    ---------------------------------         WTI Price
  December 31       Subject Leases (a)       Trust (b)        Per Barrel
  -----------       ------------------       ---------        ----------
                                 (Million STB)

     1998                1,075.4                0.0            $ 12.05
     1999                1,007.6               93.6              25.60
     2000                  999.6               90.7              26.83
     2001                  961.7               43.2              19.78
     2002                  908.7               85.8              31.23


                                       18
<PAGE>

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

(a)  Includes proved  undeveloped  reserves of 109.8 million STB at December 31,
     1998;  108 million STB at December 31, 1999;  137.3 million STB at December
     31, 2000;  112.5  million STB at December 31, 2001;  and 5.5 million STB at
     December 31, 2002.

(b)  Includes  proved  undeveloped  reserves of 4.5 million STB at December  31,
     1999;  6.4  million  STB at  December  31,  2000;  and 0.03  million STB at
     December 31, 2002. No proved undeveloped  reserves were attributable to the
     Trust at December 31, 1998 and December 31, 2001.

     The  reserve  volumes  attributable  to the  Trust are  estimated  using an
allocation  of reserve  volumes  based on estimated  future  production  and the
current WTI Price, and assume no future movement in the Consumer Price Index and
no future  additions by the Company of proved  reserves.  The estimated  reserve
volumes   attributable  to  the  Trust  will  vary  if  different  estimates  of
production,  prices  and other  factors  are used.  Even if  expected  reservoir
performance does not change, the estimated  reserves,  economic life, and future
revenues  attributable to the Trust may change significantly in the future. This
may result  from  changes in the WTI Price or from  changes in other  prescribed
variables utilized in calculations defined by the Overriding Royalty Conveyance.
See Note 6 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

                             MILLER AND LENTS, LTD.
                      INTERNATIONAL OIL AND GAS CONSULTANTS
                              TWENTY-SEVENTH FLOOR
                                 1100 LOUISIANA
                            HOUSTON, TEXAS 77002-5216
                             TELEPHONE 713 651-9455
                              TELEFAX 713 654-9914
                         email: mail@millerandlents.com


                                February 19, 2003


The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street, Floor 21 West
New York, New York 10286

                               Re: Estimates of Proved Reserves, Future
                                   Production Rates, and Future Net Revenues
                                   for the BP Prudhoe Bay Royalty Trust
                                   As of December 31, 2002
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, 2002.  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 11, 2003  addressed to Ms. Marie E.  Trimboli of The Bank of New
York and signed by Mr. Neil McCleary.  Reviews were also performed by Miller and
Lents,  Ltd.  during this year or in previous  years of (1) the  procedures  for
estimating  and  documenting  Proved  Reserves,  (2) the  estimates  of in-place
reservoir volumes, (3) the estimates of recovery factors and production profiles
for the various  areas,  pay zones,  projects,  and recovery  processes that are
included in the estimate of Proved  Reserves,  (4) the  production  strategy and
procedures  for  implementing  that  strategy,  (5) the  sufficiency of the data
available for making estimates of Proved Reserves and production  profiles,  and
(6) pertinent provisions of the Prudhoe Bay Unit Operating Agreement, the Issues
Resolution Agreement,  the Overriding Royalty Conveyance,  the Trust Conveyance,
the BP  Prudhoe  Bay  Royalty  Trust  Agreement,  and  other  related  documents
referenced in the Form F-3 Registration  Statement filed with the Securities and
Exchange Commission on August 7, 1989, by BP Exploration (Alaska) Inc.



                                       20
<PAGE>

     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, 2002,  of 85.82  million
          barrels of oil and condensate  are, in the aggregate,  reasonable.  Of
          the 85.82  million  barrels of total Proved  Reserves,  85.79  million
          barrels are Proved  Developed  Reserves,  and 0.03 million barrels are
          Proved Undeveloped Reserves.



                                       21
<PAGE>

     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, 2002,
          production of the Proved Reserves will result in Estimated  Future Net
          Revenues of $653.2  million and Present Value of Estimated  Future Net
          Revenues of $388.4 million to the BP Prudhoe Bay Royalty Trust.  These
          estimates are reasonable.

     6.   BP Exploration  (Alaska) Inc. estimated that, as of December 31, 2002,
          815.0  million  barrels of Proved  Reserves have been added to Current
          Reserves. This estimate is reasonable. Current Reserves are defined in
          the Overriding  Royalty  Conveyance as net Proved  Reserves of 2,035.6
          million  barrels as of December  31,  1987.  Net  additions  to Proved
          Reserves after December 31, 1987 affect the Chargeable  Costs that are
          used to  calculate  the Per Barrel  Royalty paid to the BP Prudhoe Bay
          Royalty Trust.

     7.   The BP Exploration (Alaska) Inc. projection that its net production of
          oil and  condensate  from Proved  Reserves will continue at an average
          rate  exceeding  90,000  barrels  per  day  until  the  year  2016  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 $31.23  per barrel on
          December 31, 2002,  current Production Taxes, and the Chargeable Costs
          adjusted as  prescribed  by the  Overriding  Royalty  Conveyance,  the
          projection that royalty  payments will continue  through the year 2018
          is reasonable. BP Exploration (Alaska) Inc. expects continued economic
          production at a declining rate through the year 2030; however, for the
          economic  conditions and production  forecast as of December 31, 2002,
          the  Per  Barrel  Royalty  will  be  zero  following  the  year  2018.
          Therefore,  no reserves are currently attributed to the BP Prudhoe Bay
          Royalty Trust after that date.

     9.   Even if expected reservoir  performance does not change, the estimated
          reserves,  economic life, and future  revenues  attributable to the BP
          Prudhoe Bay Royalty Trust may change significantly in the future. This
          may result from changes in the West Texas  Intermediate  Price or from
          changes in other prescribed variables utilized in calculations defined
          by the Overriding Royalty Conveyance.

     Estimates of ultimate and  remaining  reserves  and  production  scheduling
depend upon assumptions  regarding  expansion or  implementation  of alternative
projects  or   development   programs  and  upon   strategies   for   production
optimization.  BP Exploration (Alaska) Inc. has continual reservoir  management,
surveillance,  and planning efforts  dedicated to (1) gathering new information,


                                       22
<PAGE>

(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 seven
to nine 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,
geophysical,  and  engineering  information.   Government  policies  and  market
conditions  different  from  those  reflected  in this  study or  disruption  of


                                       23
<PAGE>

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


                                       26
<PAGE>

remitted directly to the United States Treasury. A Foreign Taxpayer may elect to
treat the income from the Royalty  Interest as  effectively  connected  with the
conduct of a United States trade or business under Internal Revenue Code section
871 or  section  882,  or  pursuant  to any  similar  provisions  of  applicable
treaties. If a Foreign Taxpayer makes this election, it is entitled to claim all
deductions  with respect to such income,  but a United States federal income tax
return  must be filed to claim  such  deductions.  This  election  once  made is
irrevocable unless an applicable treaty allows the election to be made annually.

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



                                       27
<PAGE>

ITEM 2.  PROPERTIES

     Reference is made to Item 1 for the information required by this item.

ITEM 3.  LEGAL PROCEEDINGS

     None.

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

     None.



                                       28
<PAGE>

                                    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, 2002.

                                                                  Distributions
                                    High              Low           Per Unit
                                    ----              ---           --------
      2001:
      First Quarter                $10.63            $ 8.56          $0.924
      Second Quarter                12.44              8.31           0.662
      Third Quarter                 14.94             10.94           0.611
      Fourth Quarter                15.41             11.50           0.573

      2002:
      First Quarter                $15.01            $10.98          $0.216
      Second Quarter                14.37             11.20           0.230
      Third Quarter                 14.49             10.70           0.476
      Fourth Quarter                15.10             12.50           0.585

     As of January 23, 2003,  21,400,000 Units were outstanding and were held by
928 holders of record.

     Future payments of cash  distributions are dependent on such factors as the
prevailing WTI Price, the relationship of the rate of change in the WTI Price to
the rate of change in the Consumer Price Index, the Chargeable  Costs, the rates
of Production Taxes prevailing from time to time, and the actual production from
the Prudhoe Bay Unit. See "THE ROYALTY INTEREST" in Item 1.

ITEM 6.  SELECTED FINANCIAL DATA

         The  following  table  presents  in  summary  form  selected  financial
information regarding the Trust.
<TABLE>
<CAPTION>

                                     2002           2001           2000           1999           1998
                                     ----           ----           ----           ----           ----
                                                  (In thousands, except per Unit amounts)

<S>                             <C>            <C>            <C>            <C>             <C>
Royalty revenues                $    33,061         59,934         65,026         13,443          15,163
Interest income                 $        23             70             92             60              17
Trust administration  expenses  $       822            724            732            798             614
Expenses reserve                $        --             --            500            500              --
                                -----------    -----------    -----------    -----------     -----------
Cash earnings                   $    32,262         59,280         63,886         12,205          14,566
Cash distributions              $    32,246         59,319         63,838         12,205          14,566
Cash distributions per unit     $     1.507          2.772          2.983          0.570           0.681
Units outstanding                21,400,000     21,400,000     21,400,000     21,400,000      21,400,000
</TABLE>



                                       29
<PAGE>

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

Cautionary Statement
--------------------

     The Trustee,  its officers or its agents on behalf of the Trustee may, from
time  to  time,  make  forward-looking  statements  (other  than  statements  of
historical  fact).  When  used  herein,  the  words  "anticipates,"   "expects,"
"believes,"  "intends" or  "projects"  and similar  expressions  are intended to
identify  forward-looking  statements.  To the extent  that any  forward-looking
statements  are made,  the  Trustee is unable to predict  future  changes in oil
prices,  oil production levels,  economic activity,  legislation and regulation,
and certain  changes in expenses of the Trust.  In addition,  the Trust's future
results of operations  and other forward  looking  statements  contained in this
item and elsewhere in this report  involve a number of risks and  uncertainties.
As a result of variations in such factors,  actual results may differ materially
from any forward looking statements.  Some of these factors are described below.
The Trustee  disclaims any obligation to update forward  looking  statements and
all such forward-looking  statements in this document are expressly qualified in
their entirety by the cautionary statements in this paragraph.

Liquidity and Capital Resources
-------------------------------

     The Trust is a passive entity, and the Trustee's  activities are limited to
collecting and  distributing  the revenues from the Royalty  Interest and paying
liabilities  and  expenses of the Trust.  Generally,  the Trust has no source of
liquidity and no capital  resources  other than the revenue  attributable to the
Royalty  Interest that it receives from time to time. See the  discussion  under
"THE ROYALTY INTEREST" in Item 1 for a description of the calculation of the Per
Barrel  Royalty,  and the  discussion  under  "THE  PRUDHOE  BAY UNIT -  Reserve
Estimates"  and  "INDEPENDENT  OIL AND GAS  CONSULTANTS'  REPORT"  in Item 1 for
information  concerning the estimated future net revenues of the Trust. However,
the Trustee does have a limited power to borrow,  establish a cash  reserve,  or
dispose of all or part of the Trust Estate, under limited circumstances pursuant
to the terms of the Trust  Agreement.  See the discussion  under "BUSINESS - The
Trust" in Item 1.

     The decline in WTI Prices  during the fourth  quarter of 1998 and the first
quarter of 1999  resulted  in the Trust not  receiving  quarterly  distributions
during the first and second  quarters of 1999.  See "THE ROYALTY  INTEREST - Per
Barrel  Royalty  Calculations.  Upon the increase in the WTI Price in the second
quarter of 1999 and the  resumption  of  distributions  in the third  quarter of
1999, the Trustee  established a cash reserve to provide  liquidity to the Trust
during any future  periods in which the Trust does not  receive a  distribution.
The Trustee set aside  $1,000,000 in the cash reserve  account,  from  quarterly
distributions  received  by the  Trust,  in four  equal  quarterly  installments
commencing with the July 1999 distribution. The Trustee will draw funds from the
cash  reserve  account  during any quarter in which the  quarterly  distribution
received by the Trust does not exceed the liabilities and expenses of the Trust,
and will replenish the reserve from future quarterly distributions, if any.

     Amounts  set  aside  for  the  cash  reserve  are  being  invested  in U.S.
government  or agency  securities  secured  by the full  faith and credit of the
United States.  Interest income received by the Trust from the investment of the
reserve fund is added to the distributions received from the Company and paid to
the holders of Units on each Quarterly Record Date. The Trustee anticipates that
it will keep this cash reserve program in place until termination of the Trust.



                                       30
<PAGE>

     As  discussed  under  "BUSINESS  -  Certain  Tax  Considerations",  amounts
received by the Trust as quarterly  distributions (and earnings on investment of
the cash reserve) are income to the holders of the Units for the taxable year in
which such amounts are received by the Trust and must be reported by the holders
of the Units even if a portion of such amounts are used to repay  borrowings  by
the Trust or add to the cash  reserve and are not received by the holders of the
Units.

Results of Operations
---------------------

     Relatively  modest  changes in oil  prices  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.

     Royalty  revenues  are  generally  received  on the  Quarterly  Record Date
(generally  the  fifteenth  day of the month)  following the end of the calendar
quarter in which the related Royalty Production  occurred.  The Trustee,  to the
extent  possible,  pays  all  expenses  of the  Trust  for each  quarter  on the
Quarterly  Record Date on which the revenues for the quarter are  received.  For
the statement of cash earnings and  distributions,  revenues and Trust  expenses
are recorded on a cash basis and, as a result,  distributions to Unit holders in
each  calendar  year  ending  December  31 are  attributable  to  the  Company's
operations during the twelve-month period ended on the preceding September 30.

     As long as the Company's  average daily net production from the Prudhoe Bay
Unit exceeds 90,000 Barrels,  which the Company currently projects will continue
until the year  2018,  the only  factors  affecting  the  Trust's  revenues  and
distributions  to Unit  holders  are  changes in WTI  Prices,  scheduled  annual
increases in Chargeable Costs,  changes in the Consumer Price Index,  changes in
Production  Taxes,  changes in the expenses of the Trust,  contributions  to the
cash reserve and interest earned on the cash reserve.

     During the year 2002 and the period of 2003 up to the date of this  report,
the WTI Prices  have been above the level  necessary  for the Trust to receive a
Per Barrel Royalty.  Whether the Trust will be entitled to future  distributions
during the  remainder  of 2003 will depend on WTI Prices  prevailing  during the
remainder of the year.

2002 compared to 2001
---------------------

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



                                       31
<PAGE>

2001 compared to 2000
---------------------

     Royalty revenues and cash  distributions in 2001 decreased by approximately
7.8% and 7.1%,  respectively,  from 2000.  Although the average WTI Price during
the 12 months ended  September 30, 2001 increased by about 1.4% from the average
price during the same period in 2000,  the increase was offset by an increase of
approximately  9.7% in Adjusted  Chargeable Costs,  primarily as a result of the
scheduled  increase  in  Chargeable  Costs from  $10.00 per Barrel to $10.75 per
Barrel  in the  first  quarter  of 2001  and  continued  increases  in the  Cost
Adjustment Factor (see "THE ROYALTY INTEREST-Per Barrel Royalty Calculations" in
Item 1).

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

     Not applicable.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                          BP PRUDHOE BAY ROYALTY TRUST
                          INDEX TO FINANCIAL STATEMENTS

                                                                            Page
                                                                            ----

Independent Auditors' Report..................................................33

Statements of Assets, Liabilities and Trust Corpus
  as of December 31, 2002 and 2001............................................34

Statement of Cash Earnings and Distributions for the years ended
  December 31, 2002, 2001 and 2000............................................35

Statements of Changes in Trust Corpus for the years ended
  December 31 2002, 2001 and 2000.............................................36

Notes to Financial Statements.................................................37





                                       32
<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, 2002 and 2001,
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,
2002.  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  auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by the Trustee,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

     As described in note 2, these financial  statements have been prepared on a
modified  basis of cash  receipts and  disbursements,  which is a  comprehensive
basis of accounting other than accounting  principles  generally accepted in the
United States of America.

     In our opinion,  the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of BP Prudhoe
Bay Royalty  Trust as of December 31, 2002 and 2001,  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, 2002, on the basis of accounting  described
in note 2.


                                               /s/KPMG LLP
                                               KPMG LLP


New York, New York
March 18, 2003



                                       33
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                Statement of Assets, Liabilities and Trust Corpus
        (Prepared on a modified basis of cash receipts and disbursements)

                                 (In thousands)
<TABLE>
<CAPTION>

                                                      December 31,            December 31,
                                                          2002                    2001
                                                          ----                    ----
         ASSETS


<S>                                                    <C>                     <C>
Royalty Interest, net (notes 1, 2 and 3)               $  16,068               $  18,077
Cash and cash equivalents (note 2)                         1,025                   1,009
                                                       ---------               ---------

Total assets                                           $  17,093               $  19,086
                                                       =========               =========


         LIABILITIES AND TRUST CORPUS

Accrued expenses                                       $     595               $     522
Trust Corpus (40,000,000 units of beneficial
   interest authorized, 21,400,000 units issued
   and outstanding)                                       16,498                  18,564
                                                       ---------               ---------

Total liabilities and trust corpus                     $  17,093               $  19,086
                                                       =========               =========
</TABLE>











See accompanying notes to financial statements.



                                       34
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                  Statements of Cash Earnings and Distributions
        (Prepared on a modified basis of cash receipts and disbursements)

                        (In thousands, except unit data)


<TABLE>
<CAPTION>

                                                  For the Years Ended December 31,
                                              2002              2001             2000
                                              ----              ----             ----

<S>                                       <C>              <C>              <C>
Royalty revenues                          $    33,061      $    59,934      $    65,026

Interest income                                    23               70               92

Less: Trust administrative expenses              (822)            (724)            (732)

Expense reserve                                    --               --             (500)
                                          -----------      -----------      -----------

Cash earnings                             $    32,262      $    59,280      $    63,886
                                          ===========      ===========      ===========

Cash distributions                        $    32,246      $    59,319      $    63,838
                                          ===========      ===========      ===========

Cash distributions per unit               $     1.507      $     2.772      $     2.983
                                          ===========      ===========      ===========

Units outstanding                          21,400,000       21,400,000       21,400,000
                                          ===========      ===========      ===========
</TABLE>












See accompanying notes to financial statements.



                                       35
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST

                      Statements of Changes in Trust Corpus
        (Prepared on a modified basis of cash receipts and disbursements)

                                 (In thousands)


<TABLE>
<CAPTION>

                                                        For the Years Ended December 31,
                                                  2002                2001                2000
                                                  ----                ----                ----

<S>                                           <C>                 <C>                 <C>
Trust Corpus at beginning of year             $   18,564          $   20,669          $   22,626

Cash earnings                                     32,262              59,280              63,886

Increase in cash reserve                              --                  --                 500

Decrease (increase) in accrued expenses              (73)                (58)                  6

Cash distributions                               (32,246)            (59,319)            (63,838)

Amortization of Royalty Interest                  (2,009)             (2,008)             (2,511)
                                              ----------          ----------          ----------

Trust Corpus at end of year                   $   16,498          $   18,564          $   20,669
                                              ==========          ==========          ==========
</TABLE>














See accompanying notes to financial statements.



                                       36
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST
                          Notes to Financial Statements
        (Prepared on a Modified Basis of Cash Receipts and Disbursements)
                        December 31, 2002, 2001 and 2000


(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 BP p.l.c. ("BP").

     Effective  January 1, 2000,  the Company and all other  Prudhoe Bay working
     interest owners cross-assigned  interests in the Prudhoe Bay Field pursuant
     to the Prudhoe Bay Unit  Alignment  Agreement.  The  Company  retained  all
     rights,  obligations,  and  liabilities  associated  with the  Trust.  This
     transaction  is not  expected  to have a  material  effect  on the  Trust's
     operation.

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

     The  trustees  of the Trust are The Bank of New  York,  a New York  banking
     corporation,  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 for inflation) and Production  Taxes (based on
     statutory  rates  then  in  existence).   For  years  subsequent  to  2006,
     Chargeable Costs will be reduced up to a maximum amount of $1.20 per barrel
     in each  year if  additions  to the  Field's  proved  reserves  do not meet
     certain specific levels.

     The Trust is  passive,  with the  Trustee  having  only such  powers as are
     necessary for the collection and  distribution of revenues,  the payment of
     Trust liabilities, and the protection of the Royalty Interest. The Trustee,
     subject to certain conditions,  is obligated to establish cash reserves and
     borrow  funds to pay  liabilities  of the Trust when they become  due.  The
     Trustee may sell Trust  properties  only (a) as authorized by a vote of the
     Trust  Unit  Holders,  (b) when  necessary  to provide  for the  payment of


                                       37
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST
                          Notes to Financial Statements
        (Prepared on a Modified Basis of Cash Receipts and Disbursements)
                  December 31, 2002, 2001 and 2000 (continued)

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

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

(2)  BASIS OF ACCOUNTING

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

     a.   Revenues are recorded when received  (generally  within 15 days of the
          end of the preceding  quarter) and distributions to Trust Unit holders
          are recorded when paid.

     b.   Trust expenses  (which include  accounting,  engineering,  legal,  and
          other professional fees,  trustees' fees, and out-of-pocket  expenses)
          are recorded on an accrual basis.

     c.   Amortization of the Royalty  Interest is calculated based on the units
          of  production  attributable  to the  Trust  over  the  production  of
          estimated  proved reserves  attributable to the Trust at the beginning
          of  the  fiscal  year   (approximately   43,200,000,   90,700,000  and
          93,600,000 barrels of estimated proved reserves were used to calculate
          the  amortization of the Royalty Interest for the years ended December
          31, 2002, 2001 and 2000,  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 for the


                                       38
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST
                          Notes to Financial Statements
        (Prepared on a Modified Basis of Cash Receipts and Disbursements)
                  December 31, 2002, 2001 and 2000 (continued)

          years ended  December  31,  2002,  2001 and 2000 was $0.37,  $0.37 and
          $0.47,  respectively.  The Trust  evaluates  impairment of the Royalty
          Interest  by  comparing  the  undiscounted  cash flows  expected to be
          realized from the Royalty Interest to the carrying value,  pursuant to
          Statement of Financial  Accounting  Standards No. 144, "Accounting for
          the Impairment or Disposal of Long-Lived  Assets" ("SFAS 144"). If the
          expected  future  undiscounted  cash flows are less than the  carrying
          value,  the Trust  recognizes  an impairment  loss for the  difference
          between the carrying value and the estimated fair value of the Royalty
          Interest (see note 3).

     While  these  statements  differ  from  financial  statements  prepared  in
     accordance  with  accounting  principles  generally  accepted in the United
     States of America,  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.

     As of December 31, 2002 and 2001, cash equivalents which represent the cash
     reserve  consist of US  treasury  bills  with an initial  term of less than
     three months.

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

(3)  ROYALTY INTEREST

     The Royalty Interest is comprised of the following at December 31, 2002 and
     2001 (in thousands):


                                                     December 31,
                                                 --------------------
                                                 2002            2001
                                                 ----            ----

      Royalty Interest                       $  535,000      $  535,000
      Less:  Accumulated amortization          (345,414)       (343,405)
             Impairment write-down             (173,518)       (173,518)
                                             ----------      ----------

                                             $   16,068      $   18,077
                                             ==========      ==========



(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 is  reportable by the
     Unit holders on their respective tax returns.



                                       39
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST
                          Notes to Financial Statements
        (Prepared on a Modified Basis of Cash Receipts and Disbursements)
                  December 31, 2002, 2001 and 2000 (continued)

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

(5)  SUMMARY OF QUARTERLY RESULTS (UNAUDITED)

     A summary of selected quarterly  financial  information for the years ended
     December 31, 2002, 2001, and 2000 is as follows (in thousands,  except unit
     data):
<TABLE>
<CAPTION>

                                            1st Quarter       2nd Quarter      3rd Quarter       4th Quarter
                                            -----------       -----------      -----------       -----------

2002
<S>                                           <C>               <C>              <C>               <C>
     Royalty revenues                         $   4,841             5,205           10,314            12,701
     Interest income                                  7                 5                6                 5
     Trust administrative expenses                 (216)             (298)            (130)             (178)
                                              ---------         ---------        ---------         ---------
     Cash earnings                                4,632             4,912           10,190            12,528
     Cash distributions                           4,621             4,931           10,185            12,509
     Cash distributions per unit                  0.216             0.230            0.476             0.585


2001
     Royalty revenues                         $  19,932            14,418           13,269            12,315
     Interest income                                 19                17               23                11
     Trust administrative expenses                 (158)             (253)            (269)              (44)
                                              ---------         ---------        ---------         ---------
     Cash earnings                               19,793            14,182           13,023            12,282
     Cash distributions                          19,777            14,167           13,096            12,279
     Cash distributions per unit                  0.924             0.662            0.612             0.574


2000
     Royalty revenues                         $  12,105            16,841           16,425            19,655
     Interest income                                 --                16               11                65
     Trust administrative expenses                 (164)             (274)            (232)              (62)
     Expenses reserve                              (250)             (250)              --                --
                                              ---------         ---------        ---------         ---------
     Cash earnings                               11,691            16,333           16,204            19,658
     Cash distributions                          11,691            16,333           16,204            19,610
     Cash distributions per unit                  0.546             0.763            0.757             0.917
</TABLE>



                                       40
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST
                          Notes to Financial Statements
        (Prepared on a Modified Basis of Cash Receipts and Disbursements)
                  December 31, 2002, 2001 and 2000 (continued)

(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, 2002  ($31.23 per barrel),  December 31, 2001 ($19.78
     per barrel), and December 31, 2000 ($26.83 per barrel.) Because the reserve
     volumes  attributable  to the Trust are  estimated  using an  allocation of
     reserve volumes based on the estimated future production and on the current
     WTI Price,  a change in the timing of estimated  production  or a change in
     the WTI price  will  result in a change in the  Trust's  estimated  reserve
     volumes. Therefore, the estimated reserve volumes attributable to the Trust
     will vary if different production estimates and prices are used.

     In  addition  to   production   estimates  and  prices,   reserve   volumes
     attributable  to the Trust are affected by the amount of  Chargeable  Costs
     that will be deducted in determining  the Per Barrel  Royalty.  The Royalty
     Interest  includes a provision under which, in years subsequent to 2006, if
     additions  to the  Field's  proved  reserves  from  January 1, 1988  (after
     certain adjustments) do not meet certain specified levels, Chargeable Costs
     will be  reduced  up to a maximum  amount of $1.20 per barrel in each year.
     Under the provisions of FASB 69, no consideration  can be given to reserves
     not considered proved at the present time.  Accordingly,  in estimating the
     reserve volumes attributable to the Trust, Chargeable Costs were reduced by
     the maximum  amount in years  subsequent  to 1998,  after  considering  the
     amount of reserves that have been added to the Field's proved reserves from
     January 1, 1988.

     Net proved  reserves of oil and condensate  attributable to the Trust as of
     December 31, 2002,  2001 and 2000,  based on the Company's  latest  reserve
     estimate at such time,  the WTI Prices on December 31, 2002,  2001 and 2000
     and a reduction  in  Chargeable  Costs in years  subsequent  to 1998,  were
     estimated to be 86 million, 43 million and 91 million barrels, respectively
     (of which 86 million, 43 million, and 84 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


                                       41
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST
                          Notes to Financial Statements
        (Prepared on a Modified Basis of Cash Receipts and Disbursements)
                  December 31, 2002, 2001 and 2000 (continued)

     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, 2002,
     2001 and 2000, 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 $31.23, $19.78 and $26.83, respectively, were as follows (in
     thousands):

<TABLE>
<CAPTION>

                                              December 31,      December 31,     December 31,
                                                  2002              2001             2000
                                                  ----              ----             ----

<S>                                            <C>               <C>              <C>
     Future net cash flows                     $ 653,236         $ 64,584         $ 520,980
     10% annual discount for estimated
       timing of cash flows                     (264,803)         (17,543)         (214,733)
                                               ---------         --------         ---------

     Standardized measure of
       discounted future net cash
       flow relating to proved
       reserves (a)                            $ 388,433         $ 47,041         $ 306,247
                                                 =========       ========         =========
</TABLE>

     (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  $388,433,000,  $47,041,000  and
          $306,247,000  at December 31, 2002, 2001 and 2000,  respectively.  The
          following are the principal  sources of the change in the standardized
          measure of discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>

                                                        2002              2001             2000
                                                        ----              ----             ----

<S>                                                 <C>              <C>               <C>
     Revisions of prior estimates:
       Reserve volumes                              $   90,906       $   47,566        $    2,913
       WTI price                                       350,099         (314,380)           80,047
       Chargeable costs - inflation                    (11,059)         (24,397)          (26,302)
       Production taxes                                (51,886)          47,995           (10,571)
       Other                                              (186)             956            (2,187)
                                                    ----------       ----------        ----------
                                                       377,874         (242,260)           43,900

     Royalty income received (b)                       (40,759)         (44,842)          (72,853)
     Accretion of discount                               4,277           27,896            30,473
                                                    ----------       ----------        ----------

     Net increase (decrease) during the year        $  341,392       $ (259,206)       $    1,520
                                                    ==========       ==========        ==========
</TABLE>



                                       42
<PAGE>

                          BP PRUDHOE BAY ROYALTY TRUST
                          Notes to Financial Statements
        (Prepared on a Modified Basis of Cash Receipts and Disbursements)
                  December 31, 2002, 2001 and 2000 (continued)

     (b)  Royalty  income   received  for  2002,  2001  and  2000  includes  the
          following:

           Period October 1, 2002 through December 31, 2002          $ 12,538
           Period October 1, 2001 through December 31, 2001          $  4,840
           Period October 1, 2000 through December 31, 2000          $ 19,932

     The above royalty  income was received by the Trust in January  2003,  2002
     and 2001, 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, 2000                           90,711
       Production                                                      (5,395)
       Reserve estimate revisions                                       1,055
       Change caused by prices/costs                                  (43,178)
                                                                       ------

       Estimated net proved reserves of oil
         and condensate at December 31, 2001                           43,193
       Production                                                      (5,395)
       Reserve estimate revisions                                          --
       Change caused by prices/costs                                   48,020
                                                                       ------

       Estimated net proved reserves of oil
         and condensate at December 31, 2002                           85,818
                                                                       ======

       Proved reserves:

           December 31, 2000                                           90,711
                                                                       ======

           December 31, 2001                                           43,193
                                                                       ======

           December 31, 2002                                           85,818
                                                                       ======





                                       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, 2003,  there were no persons known to the Trustee to be the
beneficial owners of more than five percent of the Units.

Unit Ownership of Management
----------------------------

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

Changes in Control
------------------

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Not applicable.

ITEM 14. CONTROLS AND PROCEDURES

     Within 90 days prior to the date of this report (the "Evaluation Date") the
officer of the Trustee  signing  this report  carried out an  evaluation  of the
effectiveness of the design and operation of the Trustee's  disclosure  controls
and  procedures  for the Trust  pursuant  to Rule  13a-14  under the  Securities
Exchange Act of 1934 (the "Exchange  Act").  Based on the foregoing that officer
concluded  that  the  disclosure  controls  and  procedures  for the  Trust  are
effective in timely alerting the responsible officers of the Trustee to material
information  relating  to the  Trust  required  to be  included  in the  Trust's
Exchange Act reports.  There have been no  significant  changes in the Trustee's
internal controls or in other factors which could significantly  affect internal
controls subsequent to the date the Trustee carried out its evaluation.



                                       44
<PAGE>

                                    PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a)  FINANCIAL STATEMENTS

     The  following  financial  statements of the Trust are included in Part II,
Item 8:

          Independent Auditors' Report

          Statements of Assets,  Liabilities and Trust Corpus as of December 31,
          2002 and 2001

          Statements  of Cash  Earnings  and  Distributions  for the years ended
          December 31, 2002, 2001 and 2000

          Statements of Changes in Trust Corpus for the years ended December 31,
          2002, 2001 and 2000

          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.

     99   Sarbanes-Oxley Section 906 Certification, dated March 31, 2003.

(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, 2002.



                                       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 Vice President

March 31, 2003

     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.

     99   Sarbanes-Oxley Section 906 Certification,  dated March 31, 2003. 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).



1 As used in the overriding  royalty  conveyance  and this report,  (a) the term
"Barrel" is a unit of measure equal to 42 United States gallons  corrected to 60
degrees  Fahrenheit  temperature  and with  deductions  for  sediment  and water
content,  and (b) the term  "Stock Tank  Barrel" or "STB"  refers to a Barrel of
stabilized  oil or  condensate  at a temperature  of 60 degrees  Fahrenheit  and
sea-level atmospheric pressure (14.7 pounds per square inch absolute).