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:
6
<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: [email protected] 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
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the audited
financial statements of BP Prudhoe Bay Royalty Trust as of, and for the year
ended, December 31, 1997 and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 0
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 535,000
<DEPRECIATION> (291,976)
<TOTAL-ASSETS> 243,024
<CURRENT-LIABILITIES> 195
<BONDS> 0
0
0
<COMMON> 242,829
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 243,024
<SALES> 0
<TOTAL-REVENUES> 44,603
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 845
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 43,758
<INCOME-TAX> 0
<INCOME-CONTINUING> 43,758
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 43,758
<EPS-PRIMARY> 2.045
<EPS-DILUTED> 2.045
</TABLE>
