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, 1997
                                       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
    of incorporation or organization)             Identification No.)

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

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

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

                                          Name of Each Exchange On Which
          Title of Each Class                       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  25,  1998,  21,400,000  Units  of  Beneficial  Interest  were
outstanding. The aggregate market value of Units held by nonaffiliates (based on
the closing price of the Units in New York Stock Exchange  composite  trading on
March  27,  1997 as  reported  in The Wall  Street  Journal)  was  approximately
$315,650,000.

                    Documents Incorporated by Reference: None


<PAGE>



                                TABLE OF CONTENTS


PART I                                                                       1
         ITEM 1.   BUSINESS                                                  1
                     INTRODUCTION                                            1
                     THE ROYALTY INTEREST                                    5
                     THE UNITS                                              10
                     THE BP SUPPORT AGREEMENT                               12
                     THE PRUDHOE BAY UNIT                                   13
                     INDEPENDENT OIL AND GAS CONSULTANTS' REPORT            18
                     INDUSTRY CONDITIONS                                    23
                     CERTAIN TAX CONSIDERATIONS                             23
         ITEM 2.   PROPERTIES                                               26
         ITEM 3.   LEGAL PROCEEDINGS                                        26
         ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS          26

PART II                                                                     27
         ITEM 5.   MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS     27
         ITEM 6.   SELECTED FINANCIAL DATA                                  27
         ITEM 7.   TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL
                   CONDITION AND RESULTS OF OPERATIONS                      28
         ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA              29
         ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
                   ACCOUNTING AND FINANCIAL DISCLOSURE                      40

PART III                                                                    40
         ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT       40
         ITEM 11.  EXECUTIVE COMPENSATION                                   40
         ITEM 12.  UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                   MANAGEMENT                                               40
         ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS           40

PART IV                                                                     41
         ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
                      REPORTS ON FORM 8-K                                   41

SIGNATURES                                                                  43

INDEX TO EXHIBITS                                                           44


                                        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 Company and Standard Oil are
indirect,  wholly owned  subsidiaries  of The British  Petroleum  Company p.l.c.
("BP"). The Trustee's corporate trust offices are located at 101 Barclay Street,
New York, New York 10286 and its telephone number is (212) 815-5092.

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

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

     The Trustee has no responsibility for the operation of the Prudhoe Bay Unit
or authority  over the  Company,  Standard  Oil or BP. The  information  in this
report relating to the Prudhoe Bay Unit, the calculation of the royalty payments
and certain other matters has been furnished to the Trustee by the Company.



                                        1

<PAGE>



                                    THE TRUST

Duties and Limited Powers of Trustee

     The duties of the Trustee are as  specified in the Trust  Agreement  and by
the laws of the State of Delaware. The descriptions of certain provisions of the
Trust  Agreement in this section and  elsewhere in this report do not purport to
be complete and are  qualified by  reference to the relevant  provisions  of the
Trust Agreement, which is filed as an exhibit to this report.

     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 may sell Trust properties only as authorized by a
vote of the holders of Units, or when  necessary,  to provide for the payment of
specific  liabilities of the Trust then due (if, among other things, the Trustee
determines  that it is not  practicable  to  submit  such  sale to a vote of the
holders of Units,  and it receives an opinion of counsel to the effect that such
sale will not  adversely  affect the  classification  of the Trust as a "grantor
trust" for  federal  income tax  purposes),  or upon  termination  of the Trust.
Pledges or other  encumbrances to secure borrowings are permitted without a vote
of holders of Units if the Trustee determines such action is advisable. Any sale
of Trust properties must be for cash unless otherwise  authorized by the holders
of Units,  and the Trustee is obligated to distribute the available net proceeds
of any  such  sale to the  holders  of Units  after  establishing  reserves  for
liabilities of the Trust.

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

Employees

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

Property of the Trust

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

                                        2

<PAGE>



vant provisions of the Overriding  Royalty  Conveyance and the Trust  Conveyance
which are filed with the Securities and Exchange  Commission as exhibits to this
report.

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

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

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

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

Amendment of the Trust Agreement

     The Trust  Agreement may be amended  without a vote of the holders of Units
to cure an  ambiguity,  to  correct or  supplement  any  provision  of the Trust
Agreement that may be inconsistent  with 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 also may be
amended with the approval of a majority of the outstanding Units at a meeting of
holders of Units.  However,  no such amendment may alter the relative  rights of
Unit  holders,  unless  approved by the  affirmative  vote of 100 percent of the
holders of Units and by the Trustee, or reduce or delay the distributions to the
holders  of Units  or  effect  certain  other  changes  unless  approved  by the
affirmative  vote of 80 percent of the holders of Units and by the  Trustee.  No
amendment  will be  effective  until the Trustee has  received a ruling from the
Internal  Revenue  Service or an  opinion  of  counsel  to the effect  that such
modification  will not  adversely  affect the  classification  of the Trust as a
"grantor  trust" for  federal  income tax  purposes or cause the income from the
Trust to be treated as unrelated  business taxable income for federal income tax
purposes.


                                        3

<PAGE>



Resignation or Removal of Trustee

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

Liabilities and Contingent Reserves

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

     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.  Except in certain limited circumstances,  before establishing
such a reserve  the  Trustee  must have  received  an  opinion of counsel to the
effect that the establishment and maintenance of 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.  The  Trustee is
obligated,  subject to  certain  conditions,  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,
provided  that,  except in certain  limited  circumstances,  it has  received an
opinion of counsel to the effect described  above.  Borrowings must be repaid in
full before any further distributions are made to holders of Units.

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

                                        4

<PAGE>



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 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 or  other  entity  rendering  such
opinion.

     After  satisfying  all  existing  liabilities  and  establishing   adequate
reserves for the payment of contingent liabilities,  the Trustee will distribute
all available proceeds to the holders of Units.

     In the Trust  Agreement,  holders of Units have waived the right to seek or
secure any portion or distribution of the Royalty Interest or any other asset of
the Trust or any accounting during the term of the Trust or during any period of
liquidation and winding up.

Voting Rights of Holders of Units

     Although  holders of Units  possess  certain  voting  rights,  their voting
rights  are not  comparable  to  those of  shareholders  of a  corporation.  For
example,  there is no  requirement  for annual  meetings  of holders of Units or
annual or other periodic reelection of the Trustee.


                              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

                                        5

<PAGE>



Prudhoe  Bay Unit as of  February  28,  1989 or as  modified  thereafter  by any
redetermination  provided  under the  terms of the  Prudhoe  Bay Unit  Operating
Agreement and the Prudhoe Bay Unit Agreement (the "Subject Leases"). The Royalty
Production  is based on oil produced  from the oil rim and  condensate  produced
from the gas cap, but not on gas  production or natural gas liquids  production.
The actual average daily net  production of oil and condensate  from the Subject
Leases for any calendar  quarter is the total  production of oil and  condensate
for such quarter,  net of the State of Alaska royalty,  divided by the number of
days in such quarter.

Per Barrel Royalty

     The "Per Barrel  Royalty"  in effect for any day is an amount  equal to the
WTI Price for such day less the sum of (i) the product of the  Chargeable  Costs
multiplied by the Cost Adjustment Factor and (ii) Production Taxes.

WTI Price

     The "WTI Price" for any trading day means (i) the latest  price  (expressed
in dollars per barrel) for West Texas intermediate crude oil of standard quality
having a specific  gravity of 40 degrees API for  delivery at Cushing,  Oklahoma
("West Texas Crude"), quoted for such trading day by the Dow Jones International
Petroleum  Report (which is published in The Wall Street  Journal) or if the Dow
Jones  International  Petroleum  Report does not publish such quotes,  then such
price as quoted by Reuters,  or if Reuters does not publish  such  quotes,  then
such price as quoted in Platt's Oilgram Price Report,  or (ii) if for any reason
such  publications  do not publish the price of West Texas  Crude,  then the WTI
Price  will  mean,  until  the  price  quotations  described  in (i)  are  again
available, the simple average of the daily mean prices (expressed in dollars per
barrel)  quoted for West Texas  Crude by one major oil  company,  one  petroleum
broker and one petroleum trading company,  in each case unaffiliated with BP and
having substantial U.S. operations. Such major oil company, petroleum broker and
petroleum  trading  company will be designated by the Company from time to time.
In the event that prices for West Texas Crude are not quoted so as to permit the
calculation  of  the  WTI  Price,  "West  Texas  Crude,"  for  the  purposes  of
calculating the WTI Price will mean such other light sweet domestic crude oil of
standard  quality as is designated by the Company and approved by the Trustee in
the  exercise  of  its  reasonable  judgment,  with  appropriate  allowance  for
transportation  costs to the Gulf  Coast  (or  other  appropriate  location)  to
equilibrate  such price to the WTI Price. The WTI Price for any day which is not
a trading day is the WTI Price for the next preceding trading day. See "INDUSTRY
CONDITIONS" below.

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, 1997 were:  $6.75 during 1993;
$8.00 during 1994;  $8.25 during 1995; $8.50 during 1996; and $8.85 during 1997.
Chargeable  Costs for the calendar year ending  December 31, 1998 and subsequent
years are shown in the following table:


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<PAGE>




    For the          Chargeable          For the          Chargeable
  Year Ending         Costs Per        Year Ending         Costs Per
  December 31          Barrel          December 31          Barrel
  -----------          ------          -----------          ------

     1998              $ 9.30             2010              $14.50
     1999                9.80             2011               16.60
     2000               10.00             2012               16.70
     2001               10.75             2013               16.80
     2002               11.25             2014               16.90
     2003               11.75             2015               17.00
     2004               12.00             2016               17.10
     2005               12.25             2017               17.20
     2006               12.50             2018               20.00
     2007               12.75             2019               23.75
     2008               13.00             2020               26.50
     2009               13.25

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

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

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

     (2) Chargeable Costs will be reduced by up to $ 1.20 per barrel in 2006 and
subsequent  years if, between January 1, 2001 and December 31, 2005,  either (a)
an additional 400,000,000 STB of proved reserves (before taking into account any
production  therefrom) have not been added to proved  reserves  allocated to the
Subject Leases (including,  for the purpose of this calculation,  a credit equal
to the number of STB of proved  reserves in excess of  300,000,000  added to the
Company's  reserves after December 31, 1987 and before January 1, 2001),  or (b)
an additional 100,000,000 STB of proved reserves (before taking into account any
production  therefrom)  have not been  added to the  reserves  allocated  to the
Subject  Leases,  without  allowing any credit for additions prior to January 1,
2001. In general,  "proved reserves" for purposes of this determination  consist
of the Company's estimate (determined to be reasonable by independent  petroleum
engineers) of the  quantities of crude oil and  condensate  that  geological and
engineering  data  demonstrate  with  reasonable  certainty to be recoverable 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:


                                        7

<PAGE>




                               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

     The Company  anticipates  further  additions  in future years to the proved
reserves  allocated  to  the  Subject  Leases.  As of  December  31,  1997,  the
cumulative additions to the proved reserves allocated to the Subject Leases were
sufficient to prevent any  reduction in  Chargeable  Costs during the years 2001
through 2005. However, downward revisions of proved reserve estimates in 1998 or
subsequent  years could result in a reduction of Chargeable Costs being required
as described above in the year 2001 or thereafter.

Cost Adjustment Factor

     The "Cost  Adjustment  Factor" is the ratio of (1) the Consumer Price Index
published for the most recently past February,  May, August or November,  as the
case may be, to (2) 121.1 (the Consumer  Price Index for January  1989),  except
that (a) if for any  calendar  quarter  the average WTI Price is $18.00 or less,
then the Cost  Adjustment  Factor for that quarter  will be the Cost  Adjustment
Factor for the immediately preceding quarter, and (b) the Cost Adjustment Factor
for any calendar quarter in which the average WTI Price exceeds $18.00,  after a
calendar  quarter  during which the average WTI Price is equal to or less than $
18.00, and for each following calendar quarter in which the average WTI Price is
greater than $18.00,  will be the product of (x) the Cost Adjustment  Factor for
the most recently past calendar  quarter in which the average WTI Price is equal
to or less than $18.00 and (y) a fraction,  the  numerator  of which will be the
Consumer Price Index published for the most recently past February,  May, August
or  November,  as the  case may be,  and the  denominator  of which  will be the
Consumer Price Index published for the most recently past February,  May, August
or November  during a quarter in which the average WTI Price is equal to or less
than $18.00.  The "Consumer Price Index" is the U.S.  Consumer Price Index,  all
items and all urban consumers,  U.S. city average,  1982-84 equals 100, as first
published,  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

                                        8

<PAGE>



Taxes payable with respect to the Royalty  Production are the Alaska Oil and Gas
Properties  Production Tax ("Alaska  Production Tax") and the Alaska Oil and Gas
Conservation  Tax ("Alaska  Conservation  Tax"). For the purposes of the Royalty
Interest,  the Alaska Production Tax is computed without regard to the "economic
limit factor," if any, as the greater of the "percentage of value amount" (based
on the statutory  rate and the wellhead  value as defined  above) and the "cents
per barrel  amount." As of the date of this report,  the statutory  rate for the
purpose of calculating the  "percentage of value amount" is 15 percent,  and the
Alaska  Conservation  Tax is a tax of $0.004  per  barrel of net  production.  A
surcharge to the Alaska  Production Tax increased  Production Taxes by $0.05 per
barrel of net production  effective July 1, 1989. Due to the spill response fund
reaching  $50  million  in 1995,  $0.02  per  barrel of the  surcharge  has been
indefinitely  suspended.  In the event the  balance of the spill  response  fund
falls below $50 million, the $0.02 per barrel surcharge will be reinstated until
the fund balance  again  reaches $50  million.  The  remaining  $0.03 per barrel
surcharge is not affected by the fund's  balance and will continue to be imposed
at all times.

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>

           Average                  Cost         Adjusted                  Per
             WTI      Chargeable  Adjustment    Chargeable   Production   Barrel
            Price       Costs      Factor         Costs        Taxes     Royalty
            -----       -----      ------         -----        -----     -------
<S>        <C>          <C>         <C>          <C>           <C>       <C>
1993:
1st Qtr    $19.85       $6.75       1.171        $ 7.90        $2.24     $ 9.71
2nd Qtr     19.76        6.75       1.180          7.96         2.22       9.57
3rd Qtr     17.77        6.75       1.180          7.96         1.92       7.88
4th Qtr     16.43        6.75       1.180          7.96         1.72       6.74

1994:
1st Qtr     14.80        8.00       1.180          9.44         1.48       3.88
2nd Qtr     17.79        8.00       1.180          9.44         1.93       6.42
3rd Qtr     18.49        8.00       1.192          9.53         2.02       6.93
4th Qtr     17.67        8.00       1.192          9.53         1.90       6.23

1995:
1st Qtr     18.35        8.25       1.200          9.90         2.00       6.45
2nd Qtr     19.32        8.25       1.212         10.00         2.11       7.21
3rd Qtr     17.87        8.25       1.212         10.00         1.90       5.98
4th Qtr     18.16        8.25       1.217         10.04         1.94       6.18

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

                                        9

<PAGE>
<TABLE>
<CAPTION>
           Average                   Cost        Adjusted                  Per
             WTI      Chargeable  Adjustment    Chargeable   Production   Barrel
            Price       Costs       Factor        Costs        Taxes     Royalty
            -----       -----       ------        -----        -----     -------
<S>        <C>          <C>          <C>         <C>           <C>       <C>
1997:
1st Qtr    $22.86       $8.85        1.265       $11.19        $2.61     $ 9.06
2nd Qtr     19.91        8.85        1.269        11.23         2.16       6.52
3rd Qtr     19.75        8.85        1.274        11.28         2.14       6.34
4th Qtr     19.94        8.85        1.280        11.33         2.16       6.45
</TABLE>

     The combination of steep declines in WTI Prices since the fourth quarter of
1997 and the increase in Chargeable Costs from $8.85 per barrel in 1997 to $9.30
per barrel in 1998 may have a material  adverse effect on the Per Barrel Royalty
payable  with  respect to the first  quarter of 1998 and,  possibly,  subsequent
quarters. See "INDUSTRY CONDITIONS" below and Item 7.

Potential Conflicts of Interest

     The  interests of the Company and the Trust with respect to the Prudhoe Bay
Unit could at times be different. In particular,  because the Per Barrel Royalty
is based on the WTI Price and Chargeable  Costs rather than the Company's actual
price  realized and actual costs,  the actual per barrel profit  received by the
Company on the Royalty Production could differ from the Per Barrel Royalty to be
paid to the Trust. It is possible,  for example,  that the relationship  between
the  Company's  actual  per  barrel  revenues  and costs  could be such that the
Company may determine to interrupt or discontinue production in whole or in part
even though a Per Barrel  Royalty may  otherwise  have been payable to the Trust
pursuant to the Royalty  Interest.  This  potential  conflict of interest  could
affect the royalties paid to Unit holders,  although the Company will be subject
to the terms of the Prudhoe Bay Unit Operating Agreement.


                                    THE UNITS

Units

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

Distributions of Income

     The Company makes  quarterly  payments to the Trust of the amounts due with
respect to the Trust's  Royalty  Interest on the fifteenth day following the end
of each calendar quarter or, if the fifteenth is not a business day, on the next
succeeding  business  day  (the  "Quarterly  Record  Date").  The  Trustee  then
distributes an amount equal to the payment  received from the Company (plus,  if
applicable,  any decrease in cash reserves previously  established for estimated
liabilities  and any other cash received by the Trustee),  less the expenses and
payments of liabilities of the Trust (plus,  if applicable,  any net increase in
cash reserves for estimated  liabilities) (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.

                                       10

<PAGE>



     The Trust  Agreement  provides  that the  Trustee  shall pay the  Quarterly
Distribution on the fifth day after the Trustee's  receipt of the amount paid by
the Company on the Quarterly Record Date, and that collected cash balances being
held by the Trustee for distribution  shall be invested in obligations issued or
unconditionally guaranteed by the United States or any agency or instrumentality
thereof  and  secured  by  the  full  faith  and  credit  of the  United  States
("Government Obligations") or, if Government Obligations with a maturity date on
the date of the  distribution  to Unit holders are not available,  in repurchase
agreements  with  banks  having  capital,   surplus  and  undivided  profits  of
$100,000,000  or more  (which  may  include  The Bank of New  York)  secured  by
Government Obligations.  If time does not permit the Trustee to invest collected
funds in  investments  of the type  described  in the  preceding  sentence,  the
Trustee may invest such funds  overnight  in a time  deposit with a bank meeting
the foregoing requirement (including The Bank of New York).

Reports to Unit Holders

     Within 90 days after the end of each  calendar  year,  the Trustee mails to
the  holders of record of Units at any time  during the  calendar  year a report
containing  information  to enable them to make the  calculations  necessary for
federal  and Alaska  income  tax  purposes,  including  the  calculation  of any
depletion  or other  deduction  which may be  available to them for the calendar
year.  In addition,  after the end of each  calendar  year the Trustee  mails to
holders of Units an annual report containing audited financial statements of the
Trust,  a letter of the  independent  petroleum  engineers  engaged by the Trust
setting  forth a summary of such firm's  determinations  regarding the Company's
estimates  of proved  reserves  and other  related  matters,  and certain  other
information required by the Trust Agreement.

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

Limited Liability of Unit Holders

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

Possible Divestiture of Units

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

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

     (ii) If any holder  fails to dispose of his Units in  accordance  with such
notice,  the Trustee will redeem, at any time during the 90-day period following
the termination of the 30-day period specified in the notice, any Unit not so

                                       11

<PAGE>



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.


                            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

                                       12

<PAGE>



the  Royalty  Interest  and under the Trust  Agreement  and the  Conveyance  are
performed.

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


                              THE PRUDHOE BAY UNIT

General

     The  Prudhoe  Bay field (the  "Field")  is  located  on the North  Slope of
Alaska,  250 miles north of the Arctic  Circle and 650 miles north of Anchorage.
The Field extends approximately 12 miles by 27 miles and contains nearly 150,000
productive acres. The Field,  which was discovered in 1968 by BP and others, has
been in production  since 1977. The Field is the largest  producing oil field in
North America. As of December 31, 1997, approximately 9.7 billion STB of oil and
condensate had been produced from the Field.  Field development is well advanced
with approximately  $17.2 billion gross capital spent and a total of about 1,790
wells drilled.  Other large fields located in the same area include the Kuparuk,
Endicott,  and Lisburne fields.  Production from those fields is not included in
the Royalty Interest.

     Since several oil companies hold acreage within the Field,  the Prudhoe Bay
Unit was  established  to  optimize  Field  development.  The  Prudhoe  Bay Unit
Operating  Agreement specifies the allocation of production and costs to Prudhoe
Bay Unit owners.  The Company and a subsidiary of the Atlantic Richfield Company
("Arco") are the two Field operators.  Other Field owners include  affiliates of
Exxon Corporation  ("Exxon"),  Mobil Corporation  ("Mobil"),  Phillips Petroleum
Company ("Phillips") and Chevron Corporation ("Chevron").

Geology

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

     The Ivishak sandstone was deposited, commencing some 250 million years ago,
during the Permian and Triassic geologic  periods.  The sediments in the Ivishak
are composed of  sandstones,  conglomerate  and shales which were deposited by a
massive  braided  river and delta  system that  flowed from an ancient  mountain

                                       13

<PAGE>



system  to the  north.  Oil was  trapped  in the  Ivishak  by a  combination  of
structural and stratigraphic trapping mechanisms.

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

Oil Characteristics

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

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

Prudhoe Bay Unit Operation and Ownership

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

     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.  Effective  December 31, 1995, the Company acquired
the interest of Amerada  Hess  Corporation  of 0.5379191  percent on the oil rim
participating  area.  Under the terms of the  Conveyance,  this  increase in the
Company's  participation  is not  allocated  to the Subject  Leases and does not
increase the Trust's Royalty Interest.

     The ownership of the Prudhoe Bay Unit by participating  area as of December
31, 1997 is summarized in the following table:

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

     BP                                     51.22% (a)        13.84%
     Arco                                   21.87             42.56
     Exxon                                  21.87             42.56
     Mobil/Phillips/Chevron                  4.44              1.04
     Others                                  0.60              0.00
                                           ------            ------
     Total                                 100.00%           100.00%
                                           ======            ======

---------------
     (a) The Trust's share of oil production is computed based on BP's ownership
interest of 50.68 percent as of February 28, 1989.

                                       14

<PAGE>



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, 1997, there were about 1,060 producing oil wells, 38 gas
reinjection  wells,  55 water  injection  wells and 127 water and  miscible  gas
injection  wells in the Field.  In terms of  individual  well  performance,  oil
production  rates  range  from 60 to 5,000  STB of oil per day.  Currently,  the
average well production rate is about 731 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  follow  during  the  periods
indicated:

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

    1993            906.8          402.2          150.0          18.2
    1994            785.5          348.4          177.5          21.5
    1995            659.3          292.4          200.0          24.2
    1996            583.1          258.6          187.6          22.7
    1997            512.8          227.4          177.1          21.4

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

Transportation of Prudhoe Bay Oil

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

     Various  protests of the Trans  Alaska  Pipeline  System  tariffs have been
filed by,  among  others,  the State of Alaska  over a period of several  years.
Proceedings  to  resolve  these  protests  are  ongoing  in the  Federal  Energy
Regulatory  Commission,  the Alaska Public  Utilities  Commission and a Court of
Appeal.

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.


                                       15

<PAGE>



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

Reserve Estimates

     The Company's net proved  remaining  reserves of oil and  condensate in the
Prudhoe Bay Unit as of  December  31, 1997 were  estimated  to be  approximately
1,166.1 million STB, of which approximately  1,154.7 million STB were associated
with the Subject Leases. This current estimate of reserves is based upon various
assumptions,  including a reasonable  estimate of the  allocation of hydrocarbon
liquids between oil and condensate pursuant to the procedures of the Prudhoe Bay
Unit Operating Agreement.  Estimates of proved reserves are inherently imprecise
and subjective and are revised over time as additional  data becomes  available.
Such  revisions  may often be  substantial.  The  Company  anticipates  that net
production  from current  proved  reserves  allocated to the Subject Leases will
exceed 90,000  barrels per day until the year 2009.  The occurrence of major gas
sales could accelerate the time at which 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,  on the basis of the economic
conditions and reserve estimates as of December 31, 1997, the Per Barrel Royalty
will be zero after the year 2009.

     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, 1997 were 64.8 million barrels of oil and condensate, of which 63.5
million  barrels were proved  developed  reserves  and 1.3 million  barrels were
proved undeveloped reserves.  Using procedures specified in Financial Accounting
Standards Board Statement of Financial  Standards No. 69, the Company calculated
that as of December 31, 1997  production of oil and  condensate  from the proved
reserves  allocated to the Trust will result in estimated future net revenues to
the Trust of $108 million,  with a present  value of $78 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 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 attrib-

                                       16

<PAGE>



utable  to the  Trust  are  estimated  by  allocating  to the Trust its share of
estimated future production from the Field, based on WTI Prices.

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

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

     1993                 1,439.9              43.2             $14.15
     1994                 1,395.0              81.0              17.75
     1995                 1,371.4              81.0              19.58
     1996                 1,247.0             111.1              25.93
     1997                 1,154.7              64.8              17.78
-------------

     (a) Includes proved  undeveloped  reserves of 243.1 million STB at December
31, 1993;  211.0 million STB at December 31, 1994; 275.2 million STB at December
31,  1995;  223.4  million STB at December 31,  1996;  and 190.2  million STB at
December 31, 1997.

     (b) Includes proved undeveloped  reserves of 0 STB at December 31, 1993 and
1994;  0.8 million STB at December  31,  1995;  9.1 million STB at December  31,
1996; and 1.3 million STB at December 31, 1997.

     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 5 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 process.  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.


                                       17

<PAGE>



                   INDEPENDENT OIL AND GAS CONSULTANTS' REPORT

           MILLER AND LENTS, LTD.                MARTIN G. MILLER (1948-1980)
           OIL AND GAS CONSULTANTS               MAX R. LENTS
            TWENTY-SEVENTH FLOOR                 KENNETH B. FORD
               1100 LOUISIANA                    P. G. VON TUNGELN
          HOUSTON, TEXAS 77002-5216              JAMES C. PEARSON
                                                 S. J. STIEBER
           TELEPHONE 713 651-9455                LARRY M. GRING
            TELEFAX 713 654-9914                 JAMES A. COLE
                                                 K. R. CHEATHAM
   email: millerandlents@worldnet.att.net        J. L. POWELL
                                                 WILLIAM P. KOZA
                                                 CHARLES G. GUFFEY
              February 10, 1998                  MICHAEL S. YOUNG
                                                 WILLIAM K. KIBLER
                                                 KAREN F. LOVING
                                                 CHRISTOPHER A. BUTTA
                                                 GREGORY W. ARMES
                                                 GARY B. KNAPP
                                                 LUCY B. KING
                                                 R. LEE COMER
                                                 GEORGE SCHAEFER
                                                 CARL D. RICHARD



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

                    Re:  Estimates of Proved Reserves,  Future Production Rates,
                         and Future Net  Revenues for the BP Prudhoe Bay Royalty
                         Trust As of December 31, 1997

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, 1997.  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 6, 1998, addressed to Ms. Marie Trimboli of The Bank of New

                                       18

<PAGE>



York and signed by Mr. Stewart N. Broome.  Reviews were also performed by Miller
and Lents,  Ltd. during this year or in previous years of (1) the procedures for
estimating  and  documenting  Proved  Reserves,  (2) the  estimates  of in-place
reservoir volumes, (3) the estimates of recovery factors and production profiles
for the various  areas,  pay zones,  projects,  and recovery  processes that are
included in the estimate of Proved  Reserves,  (4) the  production  strategy and
procedures  for  implementing  that  strategy,  (5) the  sufficiency of the data
available for making estimates of Proved Reserves and production  profiles,  and
(6) pertinent provisions of the Prudhoe Bay Unit Operating Agreement, the Issues
Resolution Agreement,  the Overriding Royalty Conveyance,  the Trust Conveyance,
the BP  Prudhoe  Bay  Royalty  Trust  Agreement,  and  other  related  documents
referenced in the Form F-3 Registration  Statement filed with the Securities and
Exchange Commission on August 7, 1989, by BP Exploration (Alaska) Inc.

     Proved  Reserves  were  estimated  by  BP  Exploration   (Alaska)  Inc.  in
accordance with the definitions  contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a). Estimated 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.

                                       19

<PAGE>



     4.   The estimated net remaining  Proved  Reserves  attributable  to the BP
          Prudhoe Bay Royalty  Trust as of December  31,  1997,  of 64.8 million
          barrels of oil and condensate  are, in the aggregate,  reasonable.  Of
          the 64.8  million  barrels  of total  Proved  Reserves,  63.5  million
          barrels are Proved  Developed  Reserves,  and 1.3 million  barrels are
          Proved Undeveloped Reserves.

     5.   Utilizing the specified  procedures  outlined in Financial  Accounting
          Standards Board Statement of Financial Accounting Standards No. 69, BP
          Exploration  (Alaska)  Inc.  calculated  that as of December 31, 1997,
          production of the Proved Reserves will result in Estimated  Future Net
          Revenues of $108  million and Present  Value of  Estimated  Future Net
          Revenues of $78 million to the BP Prudhoe  Bay  Royalty  Trust.  These
          estimates are reasonable.

     6.   BP Exploration  (Alaska) Inc. estimated that, as of December 31, 1997,
          737.7  million  barrels of Proved  Reserves have been added to Current
          Reserves. This estimate is reasonable. Current Reserves are defined in
          the Overriding  Royalty  Conveyance as net Proved  Reserves of 2,035.6
          million  barrels as of December  31,  1987.  Net  additions  to Proved
          Reserves after December 31, 1987 affect the Chargeable  Costs that are
          used to  calculate  the Per Barrel  Royalty paid to the BP Prudhoe Bay
          Royalty Trust.

     7.   The BP Exploration (Alaska) Inc. projection that its net production of
          oil and  condensate  from Proved  Reserves will continue at an average
          rate  exceeding  90,000  barrels  per  day  until  the  year  2009  is
          reasonable.  As long as the Per Barrel  Royalty has a positive  value,
          average daily  production  attributable  to the BP Prudhoe Bay Royalty
          Trust will remain constant until the net production falls below 90,000
          barrels per day; thereafter, production attributable to the BP Prudhoe
          Bay Royalty Trust will decline with the BP  Exploration  (Alaska) Inc.
          production.  However,  the Per Barrel Royalty will not have a positive
          value if the West Texas Intermediate Price is less than the sum of the
          per  barrel   Chargeable  Costs  and  per  barrel   Production  Taxes,
          appropriately  adjusted  in  accordance  with the  Overriding  Royalty
          Conveyance.   Under  such  circumstances,   average  daily  production
          attributable  to the BP Prudhoe Bay  Royalty  Trust will have no value
          and therefore  will not  contribute  to the reserves  regardless of BP
          Exploration (Alaska) Inc.'s net production level.

     8.   Based on the West  Texas  Intermediate  Price of $17.78  per barrel on
          December 31, 1997,  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 2009
          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, 1997,
          the  Per  Barrel  Royalty  will  be  zero  following  the  year  2009.
          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.


                                       20

<PAGE>



     Estimates of ultimate and  remaining  reserves  and  production  scheduling
depend upon assumptions  regarding  expansion or  implementation  of alternative
projects  or   development   programs  and  upon   strategies   for   production
optimization.  BP Exploration (Alaska) Inc. has continual reservoir  management,
surveillance,  and planning efforts  dedicated to (1) gathering new information,
(2) improving the accuracy of its reserves and  production  capacity  estimates,
(3) recognizing and exploiting new  opportunities,  (4)  anticipating  potential
problems and taking  corrective  actions,  and (5) identifying,  selecting,  and
implementing  optimum  recovery program and cost reduction  alternatives.  Given
this significant  effort and  ever-changing  economic  conditions,  estimates of
reserves and production profiles will change periodically.

     The current  estimate of Proved  Reserves  includes only those  projects or
development programs that are deemed reasonably certain to be implemented, given
current  economic  and  regulatory  conditions.  Future  projects,   development
programs,  or operating  strategies  different from those assumed in the current
estimates may change future estimates and affect  recoveries.  However,  because
several complementary and alternative projects are being considered for recovery
of the remaining oil in the  reservoir,  a decision not to implement a currently
planned project may allow scope expansion or  implementation of another project,
thereby increasing the overall likelihood of recovering the reserves.

     Future  production  rates will be controlled by facilities  limitations and
upsets, well downtime,  and the effectiveness of programs to optimize production
and costs. BP Exploration  (Alaska) Inc.  currently expects  continued  economic
production  from the  reservoir  at a  declining  rate  through  the year  2030.
Additional drilling, workovers, facilities modifications, new recovery projects,
and  programs  for  production  enhancement  and  optimization  are  expected to
mitigate but not  eliminate the decline in gross oil and  condensate  production
capacity.

     In making its future  production  rate forecasts,  BP Exploration  (Alaska)
Inc.  provided  for normal  downtime  and planned  facilities  upsets.  Although
allowances  for  unplanned  upsets are also  considered  in the  estimates,  the
studies  do not  provide  for any  impediments  to  crude  oil  production  as a
consequence of major disruptions.

     Under current economic conditions, gas from the Alaskan North Slope, except
for  minor  volumes,  cannot  be  marketed  commercially.   Oil  and  condensate
recoveries  are expected to be greater as a result of continued  reinjection  of
produced gas than the recoveries  would be if major volumes of produced gas were
being sold. No major gas sale is assumed in the current estimates.  If major gas
sales are  determined to be  economically  viable in the future,  BP Exploration
(Alaska) Inc.  estimates that such sales would not actually commence until eight
to ten years after such a  determination.  In the event that major gas sales are
initiated,  ultimate  oil and  condensate  recoveries  may be  reduced  from the
current  estimates  unless  recovery  projects  other than those included in the
current estimates are implemented.

     Large volumes of natural gas liquids are likely to be produced and marketed
in the future whether or not major gas sales become viable.  Natural gas liquids
reserves  are not included in the  estimates  cited  herein.  The BP Prudhoe Bay
Royalty Trust is not entitled to royalty  payments  from  production or sales of
natural gas or natural gas liquids.

     The  evaluations  presented in this report,  with the  exceptions  of those
parameters specified by others, reflect our informed judgments based on accepted
standards  of  professional  investigation  but are  subject to those  generally
recognized   uncertainties   associated  with   interpretation   of  geological,
geophysical,  and  engineering  information.   Government  policies  and  market
conditions  different  from  those  reflected  in this  study or  disruption  of
existing transportation routes or facilities may cause the total quantity of oil

                                       21

<PAGE>



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.             [STATE OF TEXAS
                                                                    *
                                                            WILLIAM P. KOZA
                         By /s/ William P. Koza                   58894
                            -------------------
                            William P. Koza                    REGISTERED
                            Vice President                    PROFESSIONAL
                                                                ENGINEER]
WPK/hsd

                                       22

<PAGE>



                               INDUSTRY CONDITIONS

     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 laws and
regulations relating to 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.  Although 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 could result in the Company  experiencing
delays and  uncertainties  in commencing  projects.  The ultimate impact of such
legislation and regulations cannot generally be predicted.

     Oil prices are subject to  international  supply and demand.  Political and
economic  developments  in various  parts of the world and  concerted  action by
members of the  Organization  of  Petroleum  Exporting  Countries  ("OPEC")  and
non-OPEC oil exporting  countries can significantly  affect world oil supply and
oil prices.

     Since the fourth quarter of 1997,  world oil prices have declined  sharply,
falling  below $14 per barrel for the first time since  1986.  The drop in world
oil prices has been  attributed  to the economic  turmoil  affecting a number of
Asian  countries  and to an unusually  warm winter in Europe and North  America,
both of which  sharply  reduced  demand  for oil.  The  drop in  demand  for oil
coincided  with an increase  in supply.  The OPEC  cartel  increased  production
quotas in November  1997,  and several of its  members,  such as  Venezuela  and
Nigeria,  continue to exceed their quotas. In addition, the United Nations is in
the process of raising the limit on oil sales by Iraq.

     On March  22,  1998,  Saudi  Arabia,  Venezuela  and  Mexico  announced  an
agreement  among OPEC and some non-OPEC oil exporting  countries to reduce world
output  by up to  2,000,000  barrels  per day.  If the  parties  adhere  to this
agreement,  it may result in an increase  oil prices.  However,  due to the many
political,  economic and other factors  influencing oil prices, the duration and
magnitude  of any  recovery  in oil  prices  is  uncertain  and  there can be no
assurance  that oil prices in the near future will recover to, or approach,  the
price levels that have pertained during the past two years.


                           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.

                                       23

<PAGE>



     Unit holders are urged to consult their tax advisors  regarding the effects
on their specific tax situations of owning and disposing of Units.


Federal Income Tax

Classification of the Trust

     The following discussion assumes that the Trust is properly classified as a
grantor  trust  under  current  law  and  is  not an  association  taxable  as a
corporation.

General Features of Grantor Trust Taxation

     A grantor  trust is not  subject to tax,  and its  beneficiaries  (the Unit
holders in the case of the Trust) are  considered  for tax  purposes  to own the
assets of the trust directly.  The Trust pays no federal income tax but files an
information  return reporting all items of income or deduction.  If a court were
to hold that the Trust is an  association  taxable as a  corporation,  the Trust
would  incur  substantial  income  tax  liabilities  in  addition  to its  other
expenses.

Taxation of Unit Holders

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

                                       24

<PAGE>



or after  that  date may be  permitted  to deduct an  allowance  for  percentage
depletion if such deduction would otherwise  exceed the allowable  deduction for
cost  depletion.  In order to take  percentage  depletion,  a Unit  holder  must
qualify for the "independent producer" exemption contained in section 613A(c) of
the  Internal  Revenue Code of 1986.  Percentage  depletion is based on the Unit
holder's  gross income from the Trust  rather than on his adjusted  basis in his
Units. Any deduction for cost depletion or percentage  depletion  allowable to a
Unit holder  reduces his  adjusted  basis in his Units for purposes of computing
subsequent depletion or gain or loss on any subsequent disposition of Units.

     Unit holders must maintain  records of their adjusted basis in their Units,
make  adjustments for depletion  deductions to such basis,  and use the adjusted
basis for the computation of gain or loss on the disposition of the Units.

Taxation of Foreign Unit Holders

     Generally, a holder of Units who is a nonresident alien individual or which
is a foreign  corporation  (a  "Foreign  Taxpayer")  is subject to tax of on the
gross income produced by the Royalty  Interest at a rate equal to 30 percent (or
at a lower treaty rate, if applicable).  This tax is withheld by the Trustee and
remitted directly to the United States Treasury. A Foreign Taxpayer may elect to
treat the income from the Royalty  Interest as  effectively  connected  with the
conduct of a United States trade or business under Internal Revenue Code section
871 or  section  882,  or  pursuant  to any  similar  provisions  of  applicable
treaties. If a Foreign Taxpayer makes this election, it is entitled to claim all
deductions  with respect to such income,  but a United States federal income tax
return  must be filed to claim  such  deductions.  This  election  once  made is
irrevocable unless an applicable treaty allows the election to be made annually.

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


                                       25

<PAGE>



Backup Withholding

     A payor must  withhold  31 percent of any  reportable  payment if the payee
fails to furnish his taxpayer  identification number ("TIN") to the payor in the
required manner or if the Secretary of the Treasury  notifies the payor that the
TIN  furnished  by the  payee is  incorrect.  Unit  holders  will  avoid  backup
withholding by furnishing their correct TINs to the Trustee in the form required
by law.

State Income Taxes

     Unit holders may be required to report their share of income from the Trust
to their state of residence or commercial domicile. However, only corporate Unit
holders will need to report their share of income to the State of Alaska. Alaska
does not impose an income tax on  individuals  or estates and trusts.  All Trust
income is Alaska source income to corporate  Unit holders and should be reported
accordingly.


ITEM 2.  PROPERTIES

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


ITEM 3.  LEGAL PROCEEDINGS

     Not applicable.


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

     Not applicable.



                                       26

<PAGE>



                                     PART II

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

     The Units are listed on the New York Stock  Exchange  (ticker  symbol BPT).
The following table shows the high and low sales prices of the Units in New York
Stock Exchange composite transactions (as reported by Dow Jones Historical Stock
Quote  Reporter  Service),  and the cash  distributions  paid per Unit, for each
calendar quarter in the two years ended December 31, 1997.

                                                                 Distributions
                                   High              Low            Per Unit
                                   ----              ---            --------
     1996:
     First Quarter               $16 1/2          $14 3/8            $.386
     Second Quarter               17               14 1/4             .439
     Third Quarter                17 3/4           14 7/8             .533
     Fourth Quarter               17 7/8           16 1/4             .582

     1997:
     First Quarter                18 3/4           15 1/2             .702
     Second Quarter               16 13/16         15                 .551
     Third Quarter                18 3/16          16 1/4             .399
     Fourth Quarter               18 3/8           15 5/16            .392

     As of March 24, 1998,  21,400,000 Units  outstanding and were held by 1,385
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 "INDUSTRY CONDITIONS" in Item 1 and Item 7.

ITEM 6.  SELECTED FINANCIAL DATA

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

                            1997           1996           1995            1994           1993
                            ----           ----           ----            ----           ----
                                          (In thousands, except per Unit amounts)

<S>                    <C>            <C>             <C>             <C>           <C>
Royalty revenues       $   44,582         42,263          34,886          32,401        51,727
Interest income                21              0               0               0             0
Trust administration
  expenses                    845            750             688             658           554
                       ----------     ----------      ----------      ----------    ----------
Cash earnings          $   43,758         41,513          34,198          31,743        51,173
                       ==========     ==========      ==========      ==========    ==========

Cash distributions     $   43,758         41,513          34,198          31,743        51,173
                       ==========     ==========      ==========      ==========    ==========
Cash distributions
  per unit             $    2.045          1.940           1.598           1.483         2.391
                       ==========     ==========      ==========      ==========    ==========

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

                                                        27

<PAGE>



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

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.  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 generally  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.

Results of Operations

     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.  Both
revenues  and Trust  expenses  are  recorded  on a cash basis and,  as a result,
distributions  to Unit holders in the years ended  December  31, 1997,  1996 and
1995 are  attributable  to the  Company's  operations  during  the  twelve-month
periods ended September 30, 1997, 1996 and 1995, respectively.

     As long as the Company's  average daily net production from the Prudhoe Bay
Unit exceeds 90,000 barrels,  which the Company currently projects will continue
until the year  2009,  the only  factors  affecting  the  Trust's  revenues  and
distributions  to Unit  holders  are  changes in WTI  Prices,  scheduled  annual
increases in Chargeable Costs,  changes in the Consumer Price Index,  changes in
Production Taxes and changes in the expenses of the Trust.

     As a result of the severe drop in world oil prices during the first quarter
of 1998 (see  "INDUSTRY  CONDITIONS"  in Item 1), the royalty  revenues and cash
distributions of the Trust may be significantly reduced in the second quarter of
1998.  After giving effect to the 1998 increase in Chargeable Costs to $9.30 per
barrel  (and  assuming  no change in the Cost  Adjustment  Factor or  Production
Taxes),  on any  trading  day  during  1998 on which  the WTI Price is less than
approximately  $14.06 per barrel,  no Per Barrel Royalty is payable with respect
to that day's  Royalty  Production.  The WTI Price has fallen  below  $14.06 per
barrel on a number of  trading  days  during  the first  quarter of 1998 (at one
point  reaching  $13.23 per barrel) and, until March 23, 1998, the day after the
announcement  of an  agreement  among OPEC and  certain  non-OPEC  countries  to
restrict oil  production,  WTI Prices had not  exceeded  $15.00 per barrel since
January 1998. As a consequence,  the Trustee anticipates that the payment by the
Company on or about  April 15,  1998 of  royalties  with  respect to the quarter
ending March 31, 1998 will be materially less than the royalty payment  received
by the Trust in January  1998 with  respect to the  fourth  quarter of 1997.  If
world oil prices fail to recover significantly,  royalty payments by the Company
to the Trust with respect to subsequent quarters also may be adversely affected.
Scheduled  increases in  Chargeable  Costs in 1999 and future years will have an
increasingly  adverse  effect on royalty  payments to the Trust should world oil
prices remain at current levels


                                       28

<PAGE>



1996 compared to 1995

     Royalty revenues and cash  distributions in 1996 increased by approximately
21.2% and 21.4%,  respectively,  from 1995,  reflecting  continued  increases in
average WTI Prices,  principally in the second and third quarters of 1996,  that
outpaced  increases in Adjusted  Chargeable  Costs and Production  Taxes.  Trust
administration expenses increased by 9.0% from 1995 to 1996, but, in relation to
cash earnings, fell to 1.8% in 1996 from 2.0% in 1995.

1997 compared to 1996

     Royalty revenues and cash  distributions in 1997 increased by approximately
5.5% and 5.4%, respectively,  from 1996, principally as a result of high average
WTI Prices in the fourth quarter of 1996 and the first quarter of 1997 (see "THE
ROYALTY   INTEREST-Per   Barrel   Royalty   Calculations"   in  Item  1).  Trust
administration  expenses increased by 12.7% from 1996 to 1997, reflecting timing
differences  in the  payment  by the  Trustee  of certain  expenses,  but,  as a
percentage of cash earnings, increased only slightly to 1.9%.


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                          BP PRUDHOE BAY ROYALTY TRUST
                          INDEX TO FINANCIAL STATEMENTS

                                                                      Page
                                                                      ----

Independent Auditors' Report                                           30

Statements of Assets, Liabilities and Trust Corpus
  As of December 31, 1997 and 1996                                     31

Statements of Cash Earnings and Distributions for
  the years ended December 31, 1997, 1996 and 1995                     32

Statements of Changes in Trust Corpus for the years
  ended December 31, 1997, 1996 and 1995                               33

Notes to Financial Statements                                          34



                                       29

<PAGE>







                          Independent Auditors' Report

To the 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, 1997 and 1996,
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,
1997.  These financial  statements are the  responsibility  of the Trustee.  Our
responsibility  is to express an opinion on these financial  statements based on
our audits.

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

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

     In our opinion,  the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and Trust Corpus of BP Prudhoe
Bay Royalty  Trust as of December 31, 1997 and 1996,  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, 1997, on the basis of accounting  described
in note 2.


                                                        /s/KPMG Peat Marwick LLP
                                                           KPMG Peat Marwick LLP


New York, New York
March 13, 1998

                                       30
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

               Statements of Assets, Liabilities and Trust Corpus

                           December 31, 1997 and 1996
                        (In thousands, except unit data)
<TABLE>
<CAPTION>



         Assets                                             1997         1996
                                                            ----         ----
<S>                                                     <C>          <C>
Royalty Interest (notes 1 and 2)                        $ 535,000      535,000
    Less:  accumulated amortization                      (291,976)    (265.970)
                                                        ---------    ---------


                   Total assets                         $ 243,024      269,030
                                                        =========    =========


         Liabilities and Trust Corpus

Accrued expenses                                        $     195           90
Trust Corpus (40,000,000 units of beneficial
    interest authorized, 21,400,000 units issued
    and outstanding)                                      242,829      268,940


                   Total liabilities and Trust Corpus   $ 243,024      269,030
                                                        =========    =========
</TABLE>

See accompanying notes to financial statements.



                                       31
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

                  Statements of Cash Earnings and Distributions

              For the Years Ended December 31, 1997, 1996 and 1995
                        (In thousands, except unit data)

<TABLE>
<CAPTION>


                                      1997          1996          1995
                                      ----          ----          ----
<S>                             <C>           <C>           <C>
Royalty revenues                $    44,582        42,263        34,886

Interest income                          21             0             0

Trust administrative expenses           845           750           688
                                -----------   -----------   -----------

Cash earnings                   $    43,758        41,513        34,198
                                ===========   ===========   ===========

Cash distributions              $    43,758        41,513        34,198
                                ===========   ===========   ===========

Cash distributions per unit     $     2.045         1.940         1.598
                                ===========   ===========   ===========

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

See accompanying notes to financial statements.



                                       32
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

                      Statements of Changes in Trust Corpus

              For the Years Ended December 31, 1997, 1996 and 1995
                                 (In thousands)

<TABLE>
<CAPTION>

                                              1997         1996         1995
                                              ----         ----         ----
<S>                                       <C>          <C>          <C>
Trust Corpus at beginning of year         $ 268,940      304,544      340,193
Cash earnings                                43,758       41,513       34,198
(Increase) decrease in accrued expenses        (105)          36           (8)
Cash distributions                          (43,758)     (41,513)     (34,198)
Amortization of Royalty Interest            (26,006)     (35,640)     (35,641)
                                          ---------    ---------    ---------


Trust Corpus at end of year               $ 242,829      268,940      304,544
                                          =========    =========    =========
</TABLE>

See accompanying notes to financial statements.




                                       33
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

                          Notes to Financial Statements

                        December 31, 1997, 1996 and 1995

(1)  FORMATION OF THE TRUST AND ORGANIZATION

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

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

          The  trustees  of the  Trust  are The  Bank of New  York,  a New  York
     corporation  authorized to do a banking business,  and The Bank of New York
     (Delaware), a Delaware banking corporation. The Bank of New York (Delaware)
     serves  as  co-trustee  in order to  satisfy  certain  requirements  of the
     Delaware  Trust  Act.  The Bank of New York alone is able to  exercise  the
     rights and powers granted to the Trustee in the Trust Agreement.

          The Per Barrel  Royalty in effect for any day is equal to the price of
     West  Texas  Intermediate  crude  oil (the "WTI  Price")  for that day less
     scheduled  Chargeable Costs (adjusted in certain  situations for inflation)
     and  Production  Taxes (based on statutory  rates then in  existence).  For
     years subsequent to 2001,  Chargeable Costs will be reduced up to a maximum
     amount of $1.20 per barrel in each year if additions to the Field's  proved
     reserves do not meet certain specific levels.

          The Trust is passive,  with the Trustee having only such powers as are
     necessary for the collection and  distribution of revenues,  the payment of
     Trust liabilities and the protection of the Royalty Interest.  The Trustee,
     subject to certain conditions,  is obligated to establish cash reserves and
     borrow  funds to pay  liabilities  of the Trust when they become  due.  The
     Trustee may sell Trust  properties  only (a) as authorized by a vote of the
     Trust  Unit  holders,  (b) when  necessary  to provide  for the  payment of
     specific  liabilities of the Trust then due (subject to certain conditions)
     or  (c)  upon  termination  of  the  Trust.  Each  Trust  Unit  issued  and
     outstanding  represents an equal undivided share of beneficial  interest in
     the Trust.  Royalty  payments are received by the Trust and  distributed to
     Trust Unit holders, net of Trust expenses,  in the month succeeding the end
     of each calendar quarter.  The Trust will terminate upon the first to occur
     of the following events:

     (a)  On or prior to December 31, 2010: upon a vote of Trust Unit holders of
          not less than 70% of the outstanding Trust Units.


                                       34
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (Continued)

     (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 have been  materially  and  adversely
          affected by certain events) or upon a vote of holders of not less than
          60% of the outstanding Trust Units.

(2)  BASIS OF ACCOUNTING

          The financial  statements of the Trust are prepared on a modified cash
     basis and reflect the Trust's assets,  liabilities and Trust Corpus and the
     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   111,000,000,   80,991,000  and
          80,991,000 barrels of estimated proved reserves were used to calculate
          the  amortization of the Royalty Interest for the years ended December
          31, 1997, 1996 and 1995,  respectively).  Such amortization is charged
          directly to the Trust Corpus,  and does not affect cash earnings.  The
          daily  rate for  amortization  per net  equivalent  barrel  of oil was
          $4.82, $6.61 and $6.61 for the years ended December 31, 1997, 1996 and
          1995,  respectively.  The  remaining  unamortized  balance  of the net
          overriding  Royalty  Interest at December 31, 1997 is not  necessarily
          indicative of the fair market value of the interest held by the Trust.

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

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

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


                                       35
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (Continued)

(3)  INCOME TAXES

          The Trust files its federal tax return as a grantor  trust  subject to
     the  provisions  of  subpart E of Part I of  Subchapter  J of the  Internal
     Revenue Code of 1986, as amended,  rather than as an association taxable as
     a  corporation.  The Unit holders are treated as the owners of Trust income
     and Corpus,  and the entire taxable income of the Trust will be reported by
     the Unit holders on their respective tax returns.

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


(4)  SUMMARY OF QUARTERLY RESULTS (UNAUDITED)

          A summary of selected  quarterly  financial  information for the years
     ended December 31, 1997 and 1996 is as follows (in  thousands,  except unit
     data):
<TABLE>
<CAPTION>
                                                 1st          2nd          3rd          4th
                                               Quarter      Quarter      Quarter      Quarter
                                               -------      -------      -------      -------
<S>                                        <C>              <C>          <C>           <C>
     1997
           Royalty revenues                $    15,138       12,052        8,770        8,622
           Trust administrative expenses           107          257          221          239
                                             ---------      -------      -------       ------
           Cash earnings                        15,031       11,795        8,549        8,383
           Cash distributions                   15,031       11,795        8,549        8,383
           Cash distributions per unit           0.702        0.551        0.399        0.392

     1996
           Royalty revenues                $     8,411        9,610       11,701       12,541
           Trust administrative expenses           151          213          299           87
                                             ---------      -------      -------       ------
           Cash earnings                         8,260        9,397       11,402       12,454
           Cash distributions                    8,260        9,397       11,402       12,454
           Cash distributions per unit           0.386        0.439        0.533        0.582
</TABLE>

(5)  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.


                                       36
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (Continued)

(5), Continued

          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, 1997  ($17.53 per barrel),  December 31, 1996
     ($25.93 per barrel) and December 31, 1995 ($19.58 per barrel).  Because the
     reserve volumes attributable to the Trust are estimated using an allocation
     of reserve volumes based on estimated future  production and on the current
     WTI Price,  a change in the timing of estimated  production  or a change in
     the WTI price  will  result in a change in the  Trust's  estimated  reserve
     volumes. Therefore, the estimated reserve volumes attributable to the Trust
     will vary if different production estimates and prices are used.

          In addition  to  production  estimates  and  prices,  reserve  volumes
     attributable  to the Trust are affected by the amount of  Chargeable  Costs
     that will be deducted in determining  the Per Barrel  Royalty.  The Royalty
     Interest  includes a provision under which, in years subsequent to 2001, if
     additions  to the  Field's  proved  reserves  from  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 1997,  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, 1997,  1996 and 1995 based on the Company's  latest reserve
     estimate at such time,  the WTI Prices on December 31, 1997,  1996 and 1995
     and a reduction  in  Chargeable  Costs in years  subsequent  to 1997,  were
     estimated to be 65, 111 and 81 million barrels,  respectively (of which 64,
     102 and 80 million barrels, respectively, are proved developed).

          The standardized  measure of discounted  future net cash flow relating
     to proved reserves  disclosure required by FASB 69 assigns monetary amounts
     to proved reserves based on current prices. This discounted future net cash
     flow should not be  construed  as the current  market  value of the Royalty
     Interest.  A market  valuation  determination  would  include,  among other
     things,  anticipated  price increases and the value of additional  reserves
     not considered  proved at the present time or reserves that may be produced
     after the  currently  anticipated  end of field life. At December 31, 1997,
     1996 and 1995 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 $17.53, $25.93 and $19.58, respectively, were as follows (in
     thousands):

                                       37
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (Continued)


(5), Continued

                                    December 31, December 31, December 31,
                                        1997         1996         1995
                                        ----         ----         ----


          Future net cash flows     $ 108,455      779,517      331,052
          10% annual discount for
            estimated timing of
            cash flows                (30,649)    (367,217)    (128,458)
                                    ---------    ---------    ---------

          Standardized measure of
            discounted future net
            cash flow relating to
            proved reserves (a)     $  77,806      412,300      202,594
                                    =========    =========    =========

     (a)  The standardized  measure of discounted  future net cash flow relating
          to proved reserves,  estimated  without  reducing  Chargeable Costs in
          years subsequent to 1997,  would be $69,220,  $388,249 and $202,602 at
          December 31, 1997, 1996 and 1995, respectively.

     The following are the principal  sources of the change in the  standardized
     measure of discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>
                                                1997         1996         1995
                                                ----         ----         ----
<S>                                         <C>          <C>          <C>
          Revisions of prior estimates:
             Reserve volumes                $  33,018       21,565        1,678

             WTI price                       (417,392)     278,082       79,833
             Chargeable costs - inflation     (13,526)     (18,891)     (11,791)
             Production taxes                  63,400      (40,513)     (10,279)
             Other                             (3,006)      (1,807)      (1,504)
                                            ---------    ---------    ---------
                                             (337,506)     238,436       57,937
          Royalty income received (b)         (38,218)     (48,989)     (34,803)
          Accretion of discount                41,230       20,259       16,315
                                            ---------    ---------    ---------

          Net (decrease) increase during

            the year                        $(334,494)     209,706       39,449
                                            =========    =========    =========
</TABLE>
     (b)  Royalty income  received for 1997,  1996 and 1995 includes the royalty
          applicable  to the period  October 1, 1997  through  December 31, 1997
          ($8,773),  October 1, 1996  through  December 31, 1996  ($15,138)  and
          October 1, 1995 through December 31, 1995 ($8,411), which was received
          by the Trust in January 1998, 1997 and 1996, respectively.


                                       38
<PAGE>



                          BP PRUDHOE BAY ROYALTY TRUST

                    Notes to Financial Statements (Continued)


(5), Continued

     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, 1995             80,991
          Production                                        (5,410)
          Change in timing of estimated production          35,485
                                                       -----------

          Estimated net proved reserves of oil
            and condensate at December 31, 1996            111,066
          Production                                        (5,395)
          Change in timing of estimated production         (40,902)
                                                       -----------

          Estimated net proved reserves of oil
            and condensate at December 31, 1997             64,769
                                                       ===========
          Proved reserves:

              December 31, 1995                             80,991
                                                       ===========

              December 31, 1996                            111,066
                                                       ===========

              December 31, 1997                             64,769
                                                       ===========


As of December  31,  1997,  the 64.8  million  barrels of proved  reserves  were
comprised of 63.5 million barrels of proved  developed  reserves and 1.3 million
barrels of proved undeveloped reserves.



                                       39
<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 26, 1998,  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.


                                       40

<PAGE>



                                     PART IV

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

     (a)  FINANCIAL STATEMENTS

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

          Independent Auditors' Report

          Statements of Assets,  Liabilities and Trust Corpus
          as of December 31, 1997 and 1996

          Statements of Cash Earnings and Distributions for the years
          ended December 31, 1997, 1996, and 1995

          Statements of Changes in Trust Corpus for the years
          ended December 31, 1997, 1996, and 1995

          Notes to Financial Statements


     (b)  FINANCIAL STATEMENT SCHEDULES

     All financial statement schedules have been omitted because they are either
not  applicable,  not required or the  information is set forth in the financial
statements or notes thereto.

     (c)  EXHIBITS

     4.1  BP Prudhoe Bay Royalty Trust  Agreement  dated February 28, 1989 among
          The Standard Oil Company,  BP  Exploration  (Alaska) Inc., The Bank of
          New York, Trustee, and F. James Hutchinson, Co-Trustee.

     4.2  Overriding  Royalty  Conveyance  dated  February  27, 1989  between BP
          Exploration (Alaska) Inc. and The Standard Oil Company.

     4.3  Trust  Conveyance  dated  February  28, 1989  between The Standard Oil
          Company and BP Prudhoe Bay Royalty Trust.

     4.4  Support  Agreement  dated as of  February  28,  1989 among The British
          Petroleum Company p.l.c.,  BP Exploration  (Alaska) Inc., The Standard
          Oil Company and BP Prudhoe Bay Royalty Trust.

     27   Financial Data Schedule

                                       41

<PAGE>



     (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, 1997.


                                       42

<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

                                     THE BANK OF NEW YORK, as Trustee


                                     By: /s/ Marie Trimboli
                                         ------------------
                                         Marie Trimboli
                                         Assistant Treasurer
March 30, 1998

     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.


                                       43

<PAGE>


                                INDEX TO EXHIBITS

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

       4.1*    BP Prudhoe Bay Royalty Trust  Agreement  dated  February 28, 1989
               among The Standard Oil Company, BP Exploration (Alaska) Inc., The
               Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee.

       4.2*    Overriding  Royalty Conveyance dated February 27, 1989 between BP
               Exploration (Alaska) Inc. and The Standard Oil Company.

       4.3*    Trust Conveyance dated February 28, 1989 between The Standard Oil
               Company and BP Prudhoe Bay Royalty Trust.

       4.4*    Support Agreement dated as of February 28, 1989 among The British
               Petroleum  Company  p.l.c.,  BP  Exploration  (Alaska)  Inc., The
               standard Oil Company and BP Prudhoe Bay Royalty Trust.

      27       Financial Data Schedule.  Filed herewith.

-----------
     *    Incorporated by reference to the  correspondingly  numbered exhibit to
          the Registrant's  Annual Report on Form 10-K for the fiscal year ended
          December 31, 1996 (File No. 1- 10243).
                                       44