UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the Fiscal Year ended December 31, 2002
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 1-10243
BP PRUDHOE BAY ROYALTY TRUST
(Exact name of registrant as specified in its charter)
DELAWARE 13-6943724
State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
THE BANK OF NEW YORK, TRUSTEE
101 BARCLAY STREET
NEW YORK, NEW YORK 10286
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (212) 815-6908
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
As of March 27, 2003, 21,400,000 Units of Beneficial Interest were
outstanding. The aggregate market value of Units held by nonaffiliates (based on
the closing sale price on the New York Stock Exchange) was approximately
$120,482,000.
Documents Incorporated by Reference: None
TABLE OF CONTENTS
PART I.........................................................................1
ITEM 1. BUSINESS...........................................................1
INTRODUCTION......................................................1
THE TRUST.........................................................2
THE ROYALTY INTEREST..............................................7
THE UNITS........................................................11
THE BP SUPPORT AGREEMENT.........................................14
THE PRUDHOE BAY UNIT.............................................14
INDEPENDENT OIL AND GAS CONSULTANTS' REPORT......................20
INDUSTRY CONDITIONS AND REGULATIONS..............................25
CERTAIN TAX CONSIDERATIONS.......................................25
ITEM 2. PROPERTIES........................................................28
ITEM 3. LEGAL PROCEEDINGS.................................................28
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS...................28
PART II.......................................................................29
ITEM 5. MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS..............29
ITEM 6. SELECTED FINANCIAL DATA...........................................29
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.......................................30
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................32
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE........................................44
PART III......................................................................44
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................44
ITEM 11. EXECUTIVE COMPENSATION............................................44
ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT........44
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................44
ITEM 14. CONTROLS AND PROCEDURES...........................................44
PART IV.......................................................................45
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K..45
SIGNATURES....................................................................46
i
PART I
ITEM 1. BUSINESS
INTRODUCTION
BP Prudhoe Bay Royalty Trust (the "Trust"), a grantor trust, was created as
a Delaware business trust pursuant to the BP Prudhoe Bay Royalty Trust Agreement
dated February 28, 1989 (the "Trust Agreement") among The Standard Oil Company
("Standard Oil"), BP Exploration (Alaska) Inc. (the "Company"), The Bank of New
York, as trustee (the "Trustee"), and F. James Hutchinson, co-trustee (The Bank
of New York (Delaware), successor co-trustee). The Trustee's corporate trust
offices are located at 101 Barclay Street, New York, New York 10286 and its
telephone number is (212) 815-896-6908. The Company and Standard Oil are wholly
owned subsidiaries of BP p.l.c. ("BP").
Upon creation of the Trust, the Company conveyed to Standard Oil, and
Standard Oil, in turn, conveyed to the Trust an overriding royalty interest (the
"Royalty Interest"), which entitles the Trust to a royalty on 16.4246 percent of
the first 90,000 Barrels* of the average actual daily net production of oil and
condensate per quarter from the working interest of the Company as of February
28, 1989 in the Prudhoe Bay Unit located on the North Slope in Alaska (see "THE
PRUDHOE BAY UNIT" below). The Royalty Interest is free of any exploration and
development expenditures.
The only assets of the Trust are the Royalty Interest assigned to the Trust
and cash or cash equivalents held by the Trustee from time to time as reserves
or for distribution (the "Trust Estate"). The Trust is a passive entity, and the
Trustee has been given only such powers as are necessary for the collection and
distribution of revenues from the Royalty Interest and the payment of Trust
liabilities and expenses. The beneficial interest in the Trust is divided into
equal undivided units (the "Units"). The Units are not an interest in or an
obligation of the Company, Standard Oil or BP. The Delaware Trust Act, under
which the Trust was formed, entitles holders of the Units to the same limitation
of personal liability as stockholders of a Delaware corporation.
The Company shares control of the operation of the Prudhoe Bay Unit with
other working interest owners. The operations of the Company and the other
working interest owners are governed by an agreement dated April 1, 1977 among
the State of Alaska and such working interest owners establishing the Prudhoe
Bay Unit (the "Prudhoe Bay Unit Agreement") and an agreement dated April 1, 1977
among the working interest owners governing Prudhoe Bay Unit operations (the
"Prudhoe Bay Unit Operating Agreement"). The Company has no obligation to
continue production from the Prudhoe Bay Unit or to maintain production at any
level and may interrupt or discontinue production at any time. The operation of
the Prudhoe Bay Unit is subject to normal operating hazards incident to the
production and transportation of oil in Alaska. In the event of damage to the
Prudhoe Bay Unit which is covered by insurance, the Company has no obligation to
use insurance proceeds to repair such damage and may elect to retain such
proceeds and close damaged areas to production.
- ----------
* As used in the overriding royalty conveyance and this report, (a) the
term "Barrel" is a unit of measure equal to 42 United States gallons corrected
to 60 degrees Fahrenheit temperature and with deductionf for sediment and water
content, and (b) the term "Stock Tank Barrel" or "STB" refers to a Barrel of
stabilized oil or condensate at a temperature of 60 degrees Fahrenheit and
sea-level atmospheric pressure (14.7 pounds per square inch absolute).
1
The Trustee has no responsibility for the operation of the Prudhoe Bay Unit
or authority over the Company, Standard Oil or BP. The information in this
report relating to the Prudhoe Bay Unit, the calculation of the royalty payments
and certain other matters has been furnished to the Trustee by the Company.
THE TRUST
Duties and Limited Powers of Trustee
- ------------------------------------
The duties of the Trustee are as specified in the Trust Agreement and by
the laws of the State of Delaware. The discussion of terms of the Trust
Agreement contained herein do not purport to be complete and are qualified in
their entirety by reference to the Trust Agreement itself, which is filed as an
exhibit to this report and is available upon request from the Trustee.
The basic function of the Trustee is to collect income from the Royalty
Interest, to pay from the Trust's income and assets all expenses, charges and
obligations of the Trust, and to pay available cash to holders of Units. The
Bank of New York (Delaware) has been appointed co-trustee in order to satisfy
certain requirements of the Delaware Trust Act, but The Bank of New York alone
is able to exercise the rights and powers granted to the Trustee in the Trust
Agreement.
The Trust Agreement grants the Trustee only such rights and powers as are
necessary to achieve the purposes of the Trust. The Trust Agreement prohibits
the Trust from engaging in any business, any commercial activity or, with
certain exceptions, investment activity of any kind and from using any portion
of the assets of the Trust to acquire any oil and gas lease, royalty or other
mineral interest.
The Trustee has the right to establish a cash reserve for the payment of
material liabilities of the Trust which may become due. Such reserve can only be
set up when the Trustee has determined that it is not practical to pay such
liabilities in a subsequent quarter out of funds anticipated to be available and
that, in the absence of such reserve, the Trust Estate is subject to the risk of
loss or diminution in value or the Trustee is subject to the risk of personal
liability for such liabilities. Furthermore, the Trustee must receive an
unqualified written opinion of counsel to the effect that such reserve will not
adversely affect the classification of the Trust as a "grantor trust" for
federal income tax purposes or cause the income from the Trust to be treated as
unrelated business taxable income for federal income tax purposes unless the
Trustee is unable to obtain such opinion and determines that the failure to
establish such reserve will be materially detrimental to the Unit holders
considered as a whole or will subject the Trustee to the risk of personal
liability for such liabilities.
The Trustee has a limited power to borrow on behalf of the Trust on a
secured or unsecured basis. Such borrowing may be effected if at any time the
amount of cash on hand is not sufficient to pay liabilities of the Trust then
due. The Trustee can only borrow from an entity not affiliated with the Trustee.
Certain other conditions must also be satisfied, including, that the Trustee
must determine that it is not practical to pay such liabilities in a subsequent
quarter out of funds anticipated to be available and the Trust Estate is subject
to the risk of loss or diminution in value. The borrowing must be effected
pursuant to terms which (in the opinion of an investment banking firm or
commercial banking firm) are commercially reasonable when compared to other
available alternatives and the Trustee must receive an unqualified written
2
opinion of counsel to the effect that such borrowing will not adversely affect
the classification of the Trust as a "grantor trust" for federal income tax
purposes or cause the income from the Trust to be treated as unrelated business
taxable income for federal income tax purposes unless the Trustee is unable to
obtain such opinion and determines that the failure to effect such borrowing
will be materially detrimental to the Unit Holders considered as a whole. To
secure payment of borrowings by the Trust, the Trustee is authorized to
mortgage, pledge, grant security interests in or otherwise encumber the Trust
Estate or any portion thereof (including the Royalty Interest) and to carve out
and convey production payments. The borrowing itself and the pledges or other
encumbrances to secure borrowings are permitted without a vote of Unit holders.
In the event of such borrowings, no further Trust distributions may be made
until the indebtedness created by such borrowings has been paid in full.
The Trustee may sell Trust properties only as authorized by the affirmative
vote of the holders of Units representing 70 percent of the Units outstanding,
provided, however, that if such sale is effected in order to provide for the
payment of specific liabilities of the Trust then due and involves a part, but
not all or substantially all, of the Trust Estate, such sale shall be approved
by the affirmative vote of a majority of the holders of the Units.
The Trustee may also sell the Trust Estate, or a portion thereof, for cash
if such sale is effected in order to provide for the payment of specific
liabilities of the Trust then due, cash on hand is insufficient and the Trustee
is unable to effect a borrowing by the Trust. The Trustee must also determine
that the failure to pay such liabilities at a later date will be contrary to the
best interest of the holders of Units and that it is not practicable to submit
the sale to a vote of the Unit holders. The sale must be effected at a price
which (in the opinion of an investment banking firm or commercial banking firm)
is at least equal to the fair market value of the interest sold and is effected
pursuant to commercially reasonable terms when compared to other available
alternatives. The Trustee must receive an unqualified written opinion of counsel
to the effect that the sale will not adversely affect the classification of the
Trust as a "grantor trust" for federal income tax purposes or cause the income
from the Trust to be treated as unrelated business taxable income for federal
income tax purposes unless the Trustee is unable to obtain such opinion and
determines that the failure to effect such sale will be materially detrimental
to the Unit Holders considered as a whole. Finally, the Trustee may sell the
Trust Estate upon termination of the Trust.
Any sale of Trust properties must be for cash unless otherwise authorized
by the holders of Units. The Trustee is obligated to distribute the available
net proceeds of any such sale to the Unit holders after establishing reserves
for liabilities of the Trust.
Except in certain circumstances, the Trustee is entitled to be
indemnified out of the assets of the Trust for any liability, expense, claim,
damage or other loss incurred by it in the performance of its duties unless such
loss results from its negligence, bad faith or fraud or from its expenses in
carrying out such duties exceeding the compensation and reimbursement it is
entitled to under the Trust Agreement.
Employees
- ---------
The Trust has no employees. All administrative functions of the Trust are
performed by the Trustee.
3
Property of the Trust
- ---------------------
Except for cash and cash equivalents held by the Trustee from time to time,
the property of the Trust consists exclusively of the Royalty Interest. The
Royalty Interest was conveyed to the Trust pursuant to an Overriding Royalty
Conveyance dated February 27, 1989 between the Company and Standard Oil and a
Trust Conveyance dated February 28, 1989 between Standard Oil and the Trust. The
Overriding Royalty Conveyance and the Trust Conveyance are referred to
collectively herein as the "Conveyance." For a description of the terms of the
Royalty Interest, see "THE ROYALTY INTEREST" below. The discussion of the terms
of the Conveyance herein is qualified in its entirety by reference to the
relevant provisions of the Overriding Royalty Conveyance and the Trust
Conveyance which are filed with the Securities and Exchange Commission as
exhibits to this report.
The interest conveyed to the Trust by the Conveyance is an overriding
royalty interest consisting of the right to receive a Per Barrel Royalty for
each Barrel of Royalty Production. The meaning of these terms is more fully
described below under "THE ROYALTY INTEREST." The Trust does not have the right
to take oil and gas in kind.
The Royalty Interest constitutes a non-operational interest in minerals.
The Trust has no right to take over operations or to share in any operating
decision whatsoever with respect to the Company's working interest in the
Prudhoe Bay Unit. The Company is not obligated to continue to operate any well
or maintain in force or attempt to maintain in force any portion of its working
interest in the Prudhoe Bay Unit when, in its reasonable and prudent business
judgment such well or interest ceases to produce or is not capable of producing
oil or gas in paying quantities.
Under the terms of the Prudhoe Bay Unit Operating Agreement, if the Company
fails to pay any costs and expenses chargeable to the Company under the Prudhoe
Bay Unit Operating Agreement and the production of oil and condensate is
insufficient to pay such costs and expenses, the Royalty Interest is chargeable
with a pro rata portion of such costs and expenses and is subject to the
enforcement against it of liens granted to the operators of the Prudhoe Bay
Unit. However, in the Conveyance the Company agreed to pay timely all costs and
expenses chargeable to it and to ensure that no such costs and expenses will be
chargeable against the Royalty Interest. The Trust is not liable for any
expense, claim, damage, loss or liability incurred by the Company or others
attributable to the Company's working interest in the Prudhoe Bay Unit or to the
oil produced from it, and the Company has agreed to indemnify the Trust and hold
it harmless against any such impositions.
The Company has the right to amend or terminate the Prudhoe Bay Unit
Agreement, the Prudhoe Bay Unit Operating Agreement and any leases or
conveyances with respect to its working interest in the exercise of its
reasonable and prudent business judgment without liability to the Trust. The
Company also has the right to sell or assign all or any part of its working
interest in the Prudhoe Bay Unit, so long as the sale or assignment is expressly
made subject to the Royalty Interest and the terms and provisions of the
Conveyance.
4
Amendment of the Trust Agreement
- --------------------------------
The Trust Agreement may be amended without a vote of the holders of Units
to cure an ambiguity, to correct or supplement any provision of the Trust
Agreement that may be inconsistent with any other such provision or to make any
other provision with respect to matters arising under the Trust Agreement that
do not adversely affect the holders of Units. The Trust Agreement may also be
amended with the approval of a majority of the outstanding Units at a meeting of
holders of Units. However, no such amendment may alter the relative rights of
Unit holders, unless approved by the affirmative vote of holders of 100 percent
of the outstanding Units and by the Trustee, or reduce or delay the
distributions to the holders of Units or effect certain other changes unless
approved by the affirmative vote of holders of at least 80 percent of the
outstanding Units and by the Trustee. No amendment will be effective until the
Trustee has received a ruling from the Internal Revenue Service or an opinion of
counsel to the effect that such modification will not adversely affect the
classification of the Trust as a "grantor trust" for federal income tax purposes
or cause the income from the Trust to be treated as unrelated business taxable
income for federal income tax purposes.
Resignation or Removal of Trustee
- ---------------------------------
The Trustee may resign at any time or be removed with or without cause by
the holders of a majority of the outstanding Units. Its successor must be a
corporation organized and doing business under the laws of the United States,
any state thereof or the District of Columbia, authorized under such laws to
exercise trust powers, or a national banking association domiciled in the United
States, in either case having a combined capital, surplus and undivided profits
of at least $50,000,000 and subject to supervision or examination by federal or
state authorities. Unless the Trust already has a trustee that is a resident of
or has a principal office in the State of Delaware, then any successor trustee
will be such a resident or have such a principal office. No resignation or
removal of the Trustee shall become effective until a successor trustee shall
have accepted appointment.
Liabilities and Contingent Reserves
- -----------------------------------
Because of the passive nature of the Trust's assets and the restrictions on
the power of the Trustee to incur obligations, the only liabilities incurred by
the Trust are routine administrative expenses, such as Trustee's fees, and
accounting, legal and other professional fees.
As discussed above, the Trustee may establish a cash reserve for the
payment of material liabilities of the Trust which may become due, if the
Trustee has determined that it is not practical to pay such liabilities out of
funds anticipated to be available for subsequent quarterly distributions and
that, in the absence of such a reserve, the trust estate is subject to the risk
of loss or diminution in value or The Bank of New York is subject to the risk of
personal liability for such liabilities. The Trustee is obligated to borrow
funds required to pay liabilities of the Trust when due, and to pledge or
otherwise encumber the Trust's assets, if it determines that the cash on hand is
insufficient to pay such liabilities and that it is not practical to pay such
liabilities out of funds anticipated to be available for subsequent quarterly
distributions. Borrowings must be repaid in full before any further
distributions are made to holders of Units. As previously described, certain
other necessary conditions must also be satisfied prior to the establishment of
a cash reserve or the Trust's borrowing of funds.
5
Termination of the Trust
- ------------------------
The Trust is irrevocable and the Company has no power to terminate the
Trust. The Trust will terminate: (a) on or prior to December 31, 2010 upon a
vote of holders of not less than 70 percent of the outstanding Units, or (b)
after December 31, 2010 either (i) at such time as the net revenues from the
Royalty Interest for two successive years commencing after 2010 are less than
$1,000,000 per year, unless the net revenues during such period have been
materially and adversely affected by an event constituting force majeure, or
(ii) upon a vote of holders of not less than 60 percent of the outstanding
Units.
Upon termination of the Trust, the Company will have an option to purchase
the Royalty Interest (for cash unless holders representing 70 percent of the
Units outstanding (60 percent if the decision to terminate the Trust is made
after December 31, 2010) authorize the sale for non-cash consideration and the
Trustee has received a ruling from the Internal Revenue Service or an opinion of
counsel to the effect that such non-cash sale will not adversely affect the
classification of the Trust as a "grantor trust" for federal income tax purposes
or cause the income from the Trust to be treated as unrelated business taxable
income for federal income tax purposes) at a price equal to the greater of (i)
the fair market value of the Trust Estate as set forth in an opinion of an
investment banking firm, commercial banking firm or other entity qualified to
give an opinion as to the fair market value of the assets of the Trust, or (ii)
the number of outstanding Units multiplied by (a) the closing price of Units on
the day of termination of the Trust on the stock exchange on which the Units are
listed, or (b) if the Units are not listed on any stock exchange but are traded
in the over-the-counter market, the closing bid price on the day of termination
of the Trust as quoted on the NASDAQ National Market System. If the Units are
neither listed nor traded in the over-the-counter market, the price will be the
fair market value of the trust estate as set forth in the opinion mentioned
above.
If the Company does not exercise its option, the Trustee will sell the
Trust properties pursuant to procedures or material terms and conditions
approved by the vote of holders of 70 percent of the outstanding Units (60
percent if the sale is made after December 31, 2010), unless the Trustee
determines that it is not practicable to submit such procedures or terms to a
vote of the holders of Units, and the sale is effected at a price which is at
least equal to the fair market value of the trust estate as set forth in the
opinion mentioned above and pursuant to terms and conditions deemed commercially
reasonable by the investment banking firm, commercial banking firm or other
entity rendering such opinion.
After satisfying all existing liabilities and establishing adequate
reserves for the payment of contingent liabilities, the Trustee will distribute
all available proceeds to the holders of Units.
In the Trust Agreement, holders of Units have waived the right to seek or
secure any portion or distribution of the Royalty Interest or any other asset of
the Trust or any accounting during the term of the Trust or during any period of
liquidation and winding up.
6
Voting Rights of Holders of Units
- ---------------------------------
Although holders of Units possess certain voting rights, their voting
rights are not comparable to those of shareholders of a corporation. For
example, there is no requirement for annual meetings of holders of Units or
annual or other periodic reelection of the Trustee.
A meeting of the holders of Units may be called at any time to act with
respect to any matter which the holders of Units are authorized to act pursuant
to the Trust Agreement. Any such meeting may be called by the Trustee in its
discretion and will be called (i) as soon as practicable after receipt of a
written request by the Company or (ii) as soon as practicable after receipt of a
written request that sets forth in reasonable detail the action proposed to be
taken at such meeting and is signed by holders of Units owning not less than 25
percent of the then outstanding Units or (iii) as may be required by applicable
laws or regulations of the New York Stock Exchange. All such meetings are
required to take place in the Borough of Manhattan, The City of New York.
THE ROYALTY INTEREST
The Royalty Interest is a property right under Alaska law which burdens
production, but there is no other security interest in the reserves or
production revenues to which the Royalty Interest is entitled. The royalty
payable to the Trust under the Royalty Interest for each calendar quarter is the
sum of the product of (i) the Royalty Production and (ii) the Per Barrel Royalty
for each day in the quarter. The payment under the Royalty Interest for any
calendar quarter may not be less than zero nor more than the aggregate value of
the total production of oil and condensate from the Company's working interest
in the Prudhoe Bay Unit for such calendar quarter, net of the State of Alaska
royalty and less the value of any applicable payments made to affiliates of the
Company.
Royalty Production
- ------------------
The "Royalty Production" for each day in a calendar quarter is 16.4246
percent of the first 90,000 Barrels of the actual average daily net production
of oil and condensate for such quarter from the Prudhoe Bay (Permo-Triassic)
Reservoir and allocated to the oil and gas leases owned by the Company in the
Prudhoe Bay Unit as of February 28, 1989 or as modified thereafter by any
redetermination provided under the terms of the Prudhoe Bay Unit Operating
Agreement and the Prudhoe Bay Unit Agreement (the "Subject Leases"). The Royalty
Production is based on oil produced from the oil rim and condensate produced
from the gas cap, but not on gas production or natural gas liquids production.
The actual average daily net production of oil and condensate from the Subject
Leases for any calendar quarter is the total production of oil and condensate
for such quarter, net of the State of Alaska royalty, divided by the number of
days in such quarter.
Per Barrel Royalty
- ------------------
The "Per Barrel Royalty" in effect for any day is an amount equal to the
WTI Price for such day less the sum of (i) the product of the Chargeable Costs
multiplied by the Cost Adjustment Factor and (ii) Production Taxes. Based on the
WTI Price on December 31, 2002, current Production Taxes and Chargeable Costs
adjusted in accordance with the Conveyance, the Company estimates that Per
Barrel Royalty payments will continue through the year 2018.
7
WTI Price
- ---------
The "WTI Price" for any trading day means (i) the latest price (expressed
in dollars per Barrel) for West Texas intermediate crude oil of standard quality
having a specific gravity of 40 degrees API for delivery at Cushing, Oklahoma
("West Texas Crude"), quoted for such trading day by the Dow Jones International
Petroleum Report (which is published in The Wall Street Journal) or if the Dow
Jones International Petroleum Report does not publish such quotes, then such
price as quoted by Reuters, or if Reuters does not publish such quotes, then
such price as quoted in Platt's Oilgram Price Report, or (ii) if for any reason
such publications do not publish the price of West Texas Crude, then the WTI
Price will mean, until the price quotations described in (i) are again
available, the simple average of the daily mean prices (expressed in dollars per
Barrel) quoted for West Texas Crude by one major oil company, one petroleum
broker and one petroleum trading company, in each case unaffiliated with BP and
having substantial U.S. operations. Such major oil company, petroleum broker and
petroleum trading company will be designated by the Company from time to time.
In the event that prices for West Texas Crude are not quoted so as to permit the
calculation of the WTI Price, "West Texas Crude," for the purposes of
calculating the WTI Price will mean such other light sweet domestic crude oil of
standard quality as is designated by the Company and approved by the Trustee in
the exercise of its reasonable judgment, with appropriate allowance for
transportation costs to the Gulf Coast (or other appropriate location) to
equilibrate such price to the WTI Price. The WTI Price for any day which is not
a trading day is the WTI Price for the preceding trading day.
Chargeable Costs
- ----------------
The "Chargeable Costs" per Barrel of Royalty Production for each calendar
year are fixed amounts specified in the Conveyance and do not necessarily
represent the Company's actual costs of production. Chargeable Costs per Barrel
for the five calendar years ended December 31, 2002 were: $9.30 during 1998;
$9.80 during 1999; $10.00 during 2000; $10.75 during 2001; and $11.25 during
2002. Chargeable Costs for the calendar year ending December 31, 2003 and
subsequent years are shown in the following table:
For the Chargeable For the Chargeable
Year Ending Costs Per Year Ending Costs Per
December 31 Barrel December 31 Barrel
----------- ------ ----------- ------
2003 $ 11.75 2012 $ 16.70
2004 12.00 2013 16.80
2005 12.25 2014 16.90
2006 12.50 2015 17.00
2007 12.75 2016 17.10
2008 13.00 2017 17.20
2009 13.25 2018 20.00
2010 14.50 2019 23.75
2011 16.60 2020 26.50
After 2020, Chargeable Costs increase at a uniform rate of $2.75 per year.
Chargeable Costs will be reduced by up to $1.20 per Barrel in 2006 and
subsequent years if, between January 1, 2001 and December 31, 2005, either (a)
an additional 400,000,000 STB of proved reserves (before taking into account any
production therefrom) have not been added to proved reserves allocated to the
Subject Leases (including, for the purpose of this calculation, a credit equal
to the number of STB of proved reserves in excess of 300,000,000 added to the
8
Company's reserves after December 31, 1987 and before January 1, 2001), or (b)
an additional 100,000,000 STB of proved reserves (before taking into account any
production therefrom) have not been added to the reserves allocated to the
Subject Leases, without allowing any credit for additions prior to January 1,
2001. In general, "proved reserves" for purposes of this determination consist
of the Company's estimate (determined to be reasonable by independent petroleum
engineers) of the quantities of crude oil and condensate that geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years under existing economic and operating conditions from the Prudhoe
Bay (Permo-Triassic Reservoir) in the Prudhoe Bay Unit. See "THE PRUDHOE BAY
UNIT - Reserve Estimates" below.
As of December 31, 1987, the proved reserves of crude oil and condensate
allocated to the Subject Leases were 2,035.6 million STB. Since that date, the
Company has made the additions (and deductions) to its estimates of proved
reserves allocated to the Subject Leases (before taking into account any
production from such additions) as shown in the following table:
Additions to Proved Reserves
Year Ended ----------------------------
December 31 Annual Cumulative
----------- ------ ----------
(Million STB)
1988 42.3 42.3
1989 45.5 87.8
1990 24.0 111.8
1991 115.8 227.6
1992 144.3 371.9
1993 206.2 578.1
1994 89.9 668.0
1995 92.2 760.2
1996 (21.0) 739.2
1997 (1.5) 737.7
1998 (0.5) 737.2
1999 0.0 737.2
2000 57.3 794.5
2001 20.5 815.0
2002 0.0 815.0
Additional drilling, workovers, facilities modifications, new recovery
projects and programs for production enhancement and optimization may mitigate,
but not eliminate the recent decline in gross oil and condensate production
capacity. However, significant downward revisions of proved reserve estimates
could result in a reduction of Chargeable Costs being required as described
above in the year 2006 and thereafter.
Cost Adjustment Factor
- ----------------------
The "Cost Adjustment Factor" is the ratio of (i) the Consumer Price Index
published for the most recently past February, May, August or November, as the
case may be, to (ii) 121.1 (the Consumer Price Index for January 1989), except
that (a) if for any calendar quarter the average WTI Price is $18.00 or less,
then the Cost Adjustment Factor for that quarter will be the Cost Adjustment
Factor for the immediately preceding quarter, and (b) the Cost Adjustment Factor
for any calendar quarter in which the average WTI Price exceeds $18.00, after a
calendar quarter during which the average WTI Price is equal to or less than $
18.00, and for each following calendar quarter in which the average WTI Price is
greater than $18.00, will be the product of (x) the Cost Adjustment Factor for
the most recently past calendar quarter in which the average WTI Price is equal
to or less than $18.00 and (y) a fraction, the numerator of which will be the
9
Consumer Price Index published for the most recently past February, May, August
or November, as the case may be, and the denominator of which will be the
Consumer Price Index published for the most recently past February, May, August
or November during a quarter in which the average WTI Price is equal to or less
than $18.00. The "Consumer Price Index" is the U.S. Consumer Price Index, all
items and all urban consumers, U.S. city average, 1982-84 equals 100, as first
published, without seasonal adjustment, by the Bureau of Labor Statistics,
Department of Labor, without regard to subsequent revisions or corrections.
Production Taxes
- ----------------
"Production Taxes" are the sum of any severance taxes, excise taxes
(including windfall profit tax, if any), sales taxes, value added taxes or other
similar or direct taxes imposed upon the reserves or production, delivery or
sale of Royalty Production. Such taxes are computed at defined statutory rates.
In the case of taxes based upon wellhead or field value, the Conveyance provides
that the WTI Price less the product of $4.50 and the Cost Adjustment factor will
be deemed to be the wellhead or field value. At the present time, the Production
Taxes payable with respect to the Royalty Production are the Alaska Oil and Gas
Properties Production Tax ("Alaska Production Tax"). For the purposes of the
Royalty Interest, the Alaska Production Tax is computed without regard to the
"economic limit factor," if any, as the greater of the "percentage of value
amount" (based on the statutory rate and the wellhead value as defined above)
and the "cents per Barrel amount." As of the date of this report, the statutory
rate for the purpose of calculating the "percentage of value amount" is 15
percent. A surcharge to the Alaska Production Tax increased Production Taxes by
$0.05 per Barrel of net production effective July 1, 1989. Due to the spill
response fund reaching $50 million in 1995, $0.02 per Barrel of the surcharge
has been indefinitely suspended. In the event the balance of the spill response
fund falls below $50 million, the $0.02 per Barrel surcharge will be reinstated
until the fund balance again reaches $50 million. The remaining $0.03 per Barrel
surcharge is not affected by the fund's balance and will continue to be imposed
at all times.
Per Barrel Royalty Calculations
The following table shows how the above-described factors interacted during
each of the past five years to produce the Per Barrel Royalty paid for each of
the calendar quarters indicated. The Per Barrel Royalty with respect to each
calendar quarter is paid to the Trust on the fifteenth day of the month
following the end of the quarter. See "THE UNITS - Distributions of Income"
below.
Cost Adjusted
Average WTI Chargeable Adjustment Chargeable Production Per Barrel
Price Costs Factor Costs Taxes Royalty
----- ----- ------ ----- ----- -------
1998:
1st Qtr $15.96 $ 9.30 1.280 $11.90 $1.56 $ 2.49
2nd Qtr 14.58 9.30 1.280 11.90 1.36 1.32
3rd Qtr 14.15 9.30 1.280 11.90 1.29 0.96
4th Qtr 12.80 9.30 1.280 11.90 1.10 0.00
1999:
1st Qtr 13.08 9.80 1.280 12.54 1.13 0.00
2nd Qtr 17.44 9.80 1.280 12.54 1.79 3.11
3rd Qtr 21.71 9.80 1.287 12.61 2.42 6.68
4th Qtr 24.60 9.80 1.296 12.70 2.84 9.05
10
Cost Adjusted
Average WTI Chargeable Adjustment Chargeable Production Per Barrel
Price Costs Factor Costs Taxes Royalty
----- ----- ------ ----- ----- -------
2000:
1st Qtr $28.86 $10.00 1.307 $13.07 $3.48 $12.31
2nd Qtr 28.87 10.00 1.319 13.19 3.47 12.21
3rd Qtr 31.63 10.00 1.330 13.30 3.88 14.45
4th Qtr 31.98 10.00 1.341 13.41 3.92 14.66
2001:
1st Qtr 28.83 10.75 1.354 14.55 3.44 10.84
2nd Qtr 27.92 10.75 1.368 14.71 3.29 9.92
3rd Qtr 26.82 10.75 1.367 14.69 3.13 9.00
4th Qtr 20.41 10.75 1.366 14.68 2.17 3.56
2002:
1st Qtr 21.67 11.25 1.369 15.40 2.36 3.91
2nd Qtr 26.28 11.25 1.384 15.57 3.04 7.67
3rd Qtr 28.33 11.25 1.391 15.65 3.34 9.34
4th Qtr 28.25 11.25 1.396 15.70 3.33 9.22
Potential Conflicts of Interest
- -------------------------------
The interests of the Company and the Trust with respect to the Prudhoe Bay
Unit could at times be different. In particular, because the Per Barrel Royalty
is based on the WTI Price and Chargeable Costs rather than the Company's actual
price realized and actual costs, the actual per Barrel profit received by the
Company on the Royalty Production could differ from the Per Barrel Royalty to be
paid to the Trust. It is possible, for example, that the relationship between
the Company's actual per Barrel revenues and costs could be such that the
Company may determine to interrupt or discontinue production in whole or in part
even though a Per Barrel Royalty may otherwise have been payable to the Trust
pursuant to the Royalty Interest. This potential conflict of interest could
affect the royalties paid to Unit holders, although the Company will be subject
to the terms of the Prudhoe Bay Unit Operating Agreement.
THE UNITS
Units
- -----
Each Unit represents an equal undivided share of beneficial interest in the
Trust. The Units do not represent an interest in or an obligation of the
Company, Standard Oil or any of their respective affiliates. Units are evidenced
by transferable certificates issued by the Trustee. Each Unit entitles its
holder to the same rights as the holder of any other Unit. The Trust has no
other authorized or outstanding class of equity securities.
11
Distributions of Income
- -----------------------
The Company makes quarterly payments to the Trust of the amounts due with
respect to the Trust's Royalty Interest on the fifteenth day following the end
of each calendar quarter or, if the fifteenth is not a business day, on the next
succeeding business day (the "Quarterly Record Date"). The Trustee, to the
extent possible, pays all expenses of the Trust for each quarter on the
Quarterly Record Date. The Trustee then distributes an amount equal to the
excess, if any, of the cash received by the Trust from the Royalty Interests
over the expenses and payments of liabilities of the Trust, subject to
adjustments for changes made by the Trustee in any cash reserve established for
the payments of estimated liabilities of the Trust (the "Quarterly
Distribution") to the persons in whose names the Units were registered at the
close of business on the immediately preceding Quarterly Record Date.
The Trust Agreement provides that the Trustee shall pay the Quarterly
Distribution on the fifth day after the Trustee's receipt of the amount paid by
the Company on the Quarterly Record Date, and that collected cash balances being
held by the Trustee for distribution shall be invested in obligations issued or
unconditionally guaranteed by the United States or any agency or instrumentality
thereof and secured by the full faith and credit of the United States
("Government Obligations") or, if Government Obligations with a maturity date on
the date of the distribution to Unit holders are not available, in repurchase
agreements with banks having capital, surplus and undivided profits of
$100,000,000 or more (which may include The Bank of New York) secured by
Government Obligations. If time does not permit the Trustee to invest collected
funds in investments of the type described in the preceding sentence, the
Trustee may invest such funds overnight in a time deposit with a bank meeting
the foregoing requirement (including The Bank of New York).
Reports to Unit Holders
- -----------------------
Within 90 days after the end of each calendar year, the Trustee mails to
the holders of record of Units at any time during the calendar year a report
containing information to enable them to make the calculations necessary for
federal and Alaska income tax purposes, including the calculation of any
depletion or other deduction which may be available to them for the calendar
year. In addition, after the end of each calendar year the Trustee mails to
holders of Units an annual report containing audited financial statements of the
Trust, a letter of the independent petroleum engineers engaged by the Trust
setting forth a summary of such firm's determinations regarding the Company's
estimates of proved reserves and other related matters, and certain other
information required by the Trust Agreement.
Following the end of each quarter, the Trustee mails Unit holders a
quarterly report showing the assets and liabilities, receipts and disbursements
and income and expenses of the Trust and the Royalty Production for such
quarter.
Limited Liability of Unit Holders
- ---------------------------------
The Trust Agreement provides that the holders of Units are, to the full
extent permitted by Delaware law, entitled to the same limitation of personal
liability extended to stockholders of private corporations for profit under
Delaware law.
12
Possible Divestiture of Units
- -----------------------------
The Trust Agreement imposes no restrictions on nationality or other status
of the persons eligible to hold Units. However, the Trust Agreement provides
that if at any time the Trust or the Trustee is named a party in any judicial or
administrative proceeding seeking the cancellation or forfeiture of any property
in which the Trust has an interest because of the nationality, or any other
status, of any one or more holders, the following procedures will be applicable:
(i) The Trustee will give written notice of the existence of such
proceedings to each holder whose nationality or other status is an issue in
the proceeding. The notice will contain a reasonable summary of such
proceeding and will constitute a demand to each such holder that he dispose
of his Units within 30 days to a party not of the nationality or other
status at issue in the proceeding described in the notice.
(ii) If any holder fails to dispose of his Units in accordance with
such notice, the Trustee will redeem, at any time during the 90-day period
following the termination of the 30-day period specified in the notice, any
Unit not so transferred for a cash price per Unit equal to the closing
price of the Units on the stock exchange on which the Units are then listed
or, in the absence of any such listing, the closing bid price on the NASDAQ
National Market System if the Units are so quoted or, if not, the mean
between the closing bid and asked prices for the Units in the
over-the-counter market, in either case as of the last business day prior
to the expiration of the 30-day period stated in the notice. If the Units
are neither listed nor traded in the over-the-counter market, the price
will be the fair market value of the Units as determined by a recognized
firm of investment bankers or other competent advisor or expert.
Units redeemed by the Trustee will be cancelled. The Trustee may, in its
sole discretion, cause the Trust to borrow any amount required to redeem the
Units. If the purchase of Units from an ineligible holder by the Trustee would
result in a non-exempt "prohibited transaction" under ERISA, or under the
Internal Revenue Code of 1986, the Units subject to the Trustee's right of
redemption will be purchased by the Company or a designee thereof, at the above
described purchase price.
Issuance of Additional Units
- ----------------------------
The Trust Agreement provides that the Company or an affiliate from time to
time may assign to the Trust additional royalty interests meeting certain
conditions, and, upon satisfaction of various other conditions, including
receipt by the Trustee of a ruling from the Internal Revenue Service to the
effect that neither the existence nor the exercise of the right to assign the
additional royalty interest or the power to accept such assignment will
adversely affect the classification of the Trust as a "grantor trust" for
federal income tax purposes, the Trust may issue up to an additional 18,600,000
Units. The Company has not conveyed any additional royalty interests to the
Trust, and the Trust has not issued any additional Units, since the inception of
the Trust.
13
THE BP SUPPORT AGREEMENT
BP has agreed pursuant to the terms of a Support Agreement, dated February
28, 1989, among BP, the Company, Standard Oil and the Trust (the "Support
Agreement"), to provide financial support to the Company in meeting its payment
obligations under the Royalty Interest.
Within 30 days of notice to BP, BP will ensure that the Company is in a
position to perform its payment obligations under the Royalty Interest and to
satisfy its payment obligations to the Trust under the Trust Agreement,
including contributing to the Company such funds as are necessary to make such
payments. BP's obligations under the Support Agreement are unconditional and
directly enforceable by Unit holders.
Except as described below, no assignment, sale, transfer, conveyance,
mortgage or pledge or other disposition of the Royalty Interest will relieve BP
of its obligations under the Support Agreement.
Neither BP nor the Company may transfer or assign its rights or obligations
under the Support Agreement without the prior written consent of the Trust,
except that BP can arrange for its obligations under the Support Agreement to be
performed by any affiliate of BP, provided that BP remains responsible for
ensuring that such obligations are performed in a timely manner.
The Company may sell or transfer all or part of its working interest in the
Prudhoe Bay Unit, although such a transfer will not relieve BP of its
responsibility to ensure that the Company's payment obligations with respect to
the Royalty Interest and under the Trust Agreement and the Conveyance are
performed.
BP will be released from its obligation under the Support Agreement upon
the sale or transfer of all or substantially all of the Company's working
interest in the Prudhoe Bay Unit if the transferee agrees to assume and be bound
by BP's obligation under the Support Agreement in a writing reasonably
satisfactory to the Trustee and if the transferee is an entity having a rating
assigned to outstanding unsecured, unsupported long term debt from Moody's
Investors Service, Inc. of at least A3 or from Standard & Poor's of at least A-
or an equivalent rating from at least one nationally-recognized statistical
rating organization (after giving effect to the sale or transfer to such entity
of all or substantially all of the Company's working interest in the Prudhoe Bay
Unit and the assumption by such entity of all of the Company's obligations under
the Conveyance and of all BP's obligations under the Support Agreement).
THE PRUDHOE BAY UNIT
General
- -------
The Prudhoe Bay field (the "Field") is located on the North Slope of
Alaska, 250 miles north of the Arctic Circle and 650 miles north of Anchorage.
The Field extends approximately 12 miles by 27 miles and contains nearly 150,000
productive acres. The Field, which was discovered in 1968 by BP and others, has
been in production since 1977. The Field is the largest producing oil field in
North America. As of December 31, 2002, approximately 10.5 billion STB of oil
and condensate had been produced from the Field. Field development is well
advanced with approximately $18.3 billion gross capital spent and a total of
about 2,051 wells drilled. Other large fields located in the same area include
the Kuparuk, Endicott, and Lisburne fields. Production from those fields is not
included in the Royalty Interest.
14
Since several oil companies hold acreage within the Field, the Prudhoe Bay
Unit was established to optimize Field development. The Prudhoe Bay Unit
Operating Agreement specifies the allocation of production and costs to Prudhoe
Bay Unit owners. Prior to July 1, 2000, the Company and a subsidiary of the
Atlantic Richfield Company were the two Field operators. On July 1, 2000,
following the acquisition by BP of Atlantic Richfield Company, the Company
assumed sole-operatorship of the field. Other Field owners include affiliates of
Exxon Mobil Corporation ("Exxon Mobil"), ConocoPhillips and ChevronTexaco
Corporation.
Geology
- -------
The principal hydrocarbon accumulations at Prudhoe Bay are in the Ivishak
sandstone of the Sadlerochit Group at a depth of approximately 8,700 feet below
sea level. The Ivishak is overlain by four minor reservoirs of varying extent
which are designated the Put River, Eileen, Sag River and Shublik (collectively,
"PESS") formations. Underlying the Sadlerochit Group are the oil-bearing
Lisburne and Endicott formations. The net production referred to herein pertains
only to the Ivishak and PESS formations, collectively known as the Prudhoe Bay
(Permo-Triassic) Reservoir, and does not pertain to the Lisburne and Endicott
formations.
The Ivishak sandstone was deposited, commencing some 250 million years ago,
during the Permian and Triassic geologic periods. The sediments in the Ivishak
are composed of sandstone, conglomerate and shale which were deposited by a
massive braided river and delta system that flowed from an ancient mountain
system to the north. Oil was trapped in the Ivishak by a combination of
structural and stratigraphic trapping mechanisms.
Gross reservoir thickness is 550 feet, with a maximum oil column thickness
of 425 feet. The original oil column is bounded on the top by a gas-oil contact,
originally at 8,575 feet below sea level across the main field, and on the
bottom by an oil-water contact at approximately 9,000 feet below sea level. A
layer of heavy oil and tar overlays the oil-water contact in the main field and
has an average thickness of around 40 feet.
Oil Characteristics
- -------------------
The produced oil from the reservoir is a medium grade, low sulfur crude
with an average specific gravity of 27 degrees API. The gas cap composition is
such that, upon surfacing, a liquid hydrocarbon phase, known as condensate, is
formed.
The interests of the Unit holders are based upon oil produced from the oil
rim and condensate produced from the gas cap, but not upon gas production (which
is currently uneconomic) or natural gas liquids production stripped from gas
produced.
Prudhoe Bay Unit Operation and Ownership
- ----------------------------------------
Since several companies hold acreage within the Field's limits, a unit was
established to ensure optimum development of the Field. The Prudhoe Bay Unit,
which became effective on April 1, 1977, divided the Field into two operating
areas. Prior to July 1, 2000, the Company was the operator of the Western
Operating Area and Arco Alaska Inc. was the operator of the Eastern Operating
15
Area. Oil and condensate production came from both the Western Operating Area
and the Eastern Operating Area. On July 1, 2000, the Company assumed sole
operatorship of the field.
The Prudhoe Bay Unit Operating Agreement specifies the allocation of
production and costs to the working interest owners. The Prudhoe Bay Unit
Operating Agreement also defines operator responsibilities and voting
requirements and is unusual in its establishment of separate participating areas
for the gas cap and oil rim.
The ownership of the Prudhoe Bay Unit by participating area as of December
31, 2002 is summarized in the following table:
Oil Rim Gas Cap
BP....................................... 26.35% (a) 26.35% (b)
Exxon Mobil.............................. 36.40 36.40
ConocoPhillips........................... 36.07 36.07
Others................................... 1.18 1.18
------ ------
Total................................100.00% 100.00%
====== ======
- ---------------
(a) The Trust's share of oil production is computed based on BP's ownership
interest on the oil rim area of 50.68 percent as of February 28, 1989.
Subsequent decreases in the Company's participation were not allocated to
the Subject Leases and have not decreased the Trust's Royalty Interest.
(b) The Trust's share of condensate production is computed based on BP's
ownership interest on the oil rim area of 13.84 percent as of February 28,
1989. Subsequent increases in the Company's participation were not
allocated to the Subject Leases and have not increased the Trust's Royalty
Interest.
Historical Production
- ---------------------
Production began on June 19, 1977, with the completion of the Trans Alaska
Pipeline System. The pipeline has a capacity of approximately 1.4 million STB of
oil per day.
As of December 31, 2002 there were about 1,111 active producing oil wells,
33 gas reinjection wells, 68 water injection wells and 143 water and miscible
gas injection wells in the Field. In terms of individual well performance, oil
production rates range from 100 to 3,500 STB of oil per day. Currently, the
average well production rate is about 375 STB of oil per day.
The Company's share of the hydrocarbon liquids production from the Field
includes oil, condensate and natural gas liquids. Using the production
allocation procedures from the Prudhoe Bay Unit Operating Agreement, the Field's
production and the share of oil and condensate (net of State of Alaska royalty)
allocated to the Subject Leases have been as follows during the periods
indicated:
16
Oil Condensate
Year ------------------ --------------------
Ended Total Subject Total Subject
December 31 Field Leases Field Leases
----------- ----- ------ ----- ------
(Thousand STB per day)
1998 442.3 196.1 165.2 20.0
1999 380.9 170.7 151.5 18.3
2000 364.0 161.4 146.7 17.8
2001 324.9 144.1 131.2 15.9
2002 293.8 130.3 121.5 14.7
Transportation of Prudhoe Bay Oil
- ---------------------------------
Production from the Field is carried to Pump Station 1, which is the
starting point for the Trans Alaska Pipeline System, through two 34-inch
diameter transit lines, one from each half of the Field. At Pump Station 1,
Alyeska Pipeline Service Company, the pipeline operator, meters the oil and
pumps it south to Valdez where it is either loaded onto marine tankers or stored
temporarily. It takes the oil about seven days to make the trip in the 48-inch
diameter pipeline.
Reservoir Management
- --------------------
The Prudhoe Bay Field is a complex, combination-drive reservoir, with
widely varying reservoir properties. Reservoir management involves directing
Field activities and projects to maximize the economic value of Field reserves.
Several different oil recovery mechanisms are currently active in the
Field, including pressure depletion, gravity drainage/gas cap expansion, water
flooding and miscible gas flooding. Separate yet integrated reservoir management
strategies have been developed for the areas affected by each of these recovery
processes.
Reserve Estimates
- -----------------
The net proved remaining reserves of oil and condensate associated with the
Subject Leases is approximately 908.7 million STB as of December 31, 2002. This
current estimate of reserves is based upon various assumptions, including a
reasonable estimate of the allocation of hydrocarbon liquids between oil and
condensate pursuant to the procedures of the Prudhoe Bay Unit Operating
Agreement. Estimates of proved reserves are inherently imprecise and subjective
and are revised over time as additional data becomes available. Such revisions
may often be substantial. The Company anticipates that net production from
current proved reserves allocated to the Subject Leases will exceed 90,000
Barrels per day until the year 2016. The occurrence of major gas sales could
accelerate the time at which the Company's net production would fall below
90,000 Barrels per day, due to the consequent decline in reservoir pressure. The
Company also projects continued economic production thereafter, at a declining
rate, until the year 2030; however, for the economic conditions and production
forecast as of December 31, 2002, it is estimated that royalty payments will
cease following the year 2018.
17
The Company's reserve estimates and production assumptions and projections
are predicated upon a reasonable estimate of hydrocarbon allocation between oil
and condensate. Oil and condensate are physically produced in a commingled
stream of hydrocarbon liquids. The allocation of hydrocarbon liquids between the
oil and condensate from the Field is a theoretical calculation performed in
accordance with procedures specified in the Prudhoe Bay Unit Operating
Agreement. Due to the differences in percentages between oil and condensate, the
overall share of oil and condensate production allocated to the Subject Leases
will vary over time according to the proportions of hydrocarbon liquid being
allocated as condensate or as oil under the Prudhoe Bay Unit Operating Agreement
allocation procedures. Under the terms of an Issues Resolution Agreement entered
into by the Prudhoe Bay Unit owners in October 1990, the allocation procedures
have been adjusted to generally allocate condensate in a manner which
approximates the anticipated decline in the production of oil until an agreed
original condensate reserve of 1.175 billion Barrels has been allocated to the
working interest owners.
The reserves attributable to the Trust's Royalty Interest constitute only a
part of the overall reserves allocated to the Subject Leases. The Company has
estimated that the net remaining proved reserves attributable to the Trust as of
December 31, 2002 were 85.82 million Barrels of oil and condensate. Using
procedures specified in Financial Accounting Standards Board Statement of
Financial Standards No. 69, the Company calculated that as of December 31, 2002
production of oil and condensate from the proved reserves allocated to the Trust
will result in estimated future net revenues to the Trust of $653.2 million,
with a present value of $388.4 million. The Company's estimates of proved
reserves and the estimated future net revenues from the Prudhoe Bay Unit have
been reviewed by Miller and Lents, Ltd., independent oil and gas consultants, as
set forth in their report following this section.
There is no precise method of forecasting the allocation of reserve volumes
between the Company and the Trust. The Royalty Interest is not a working
interest and the Trust is not entitled to receive any specific volume of
reserves from the Field. Rather, reserve volumes attributable to the Trust at
any given date are estimated by allocating to the Trust its share of estimated
future production from the Field based on WTI Prices and other economic
parameters in effect on the date of the evaluation.
The following table shows the net remaining proved reserves of oil and
condensate allocated to the Subject Leases, the net proved reserves allocated to
the Trust, and the WTI Prices on the dates indicated:
Net Proved Reserves
--------------------------------- WTI Price
December 31 Subject Leases (a) Trust (b) Per Barrel
----------- ------------------ --------- ----------
(Million STB)
1998 1,075.4 0.0 $ 12.05
1999 1,007.6 93.6 25.60
2000 999.6 90.7 26.83
2001 961.7 43.2 19.78
2002 908.7 85.8 31.23
18
- -------------
(a) Includes proved undeveloped reserves of 109.8 million STB at December 31,
1998; 108 million STB at December 31, 1999; 137.3 million STB at December
31, 2000; 112.5 million STB at December 31, 2001; and 5.5 million STB at
December 31, 2002.
(b) Includes proved undeveloped reserves of 4.5 million STB at December 31,
1999; 6.4 million STB at December 31, 2000; and 0.03 million STB at
December 31, 2002. No proved undeveloped reserves were attributable to the
Trust at December 31, 1998 and December 31, 2001.
The reserve volumes attributable to the Trust are estimated using an
allocation of reserve volumes based on estimated future production and the
current WTI Price, and assume no future movement in the Consumer Price Index and
no future additions by the Company of proved reserves. The estimated reserve
volumes attributable to the Trust will vary if different estimates of
production, prices and other factors are used. Even if expected reservoir
performance does not change, the estimated reserves, economic life, and future
revenues attributable to the Trust may change significantly in the future. This
may result from changes in the WTI Price or from changes in other prescribed
variables utilized in calculations defined by the Overriding Royalty Conveyance.
See Note 6 of the Notes to Financial Statements in Item 8.
The Company is under no obligation to make investments in development
projects which would add additional non-proved resources to proved reserves and
cannot make such investments without the concurrence of the Prudhoe Bay Unit
working interest owners. However, several such investments which would augment
Prudhoe Bay projects are already in progress. These include additional drilling,
water flood expansions and miscible injection continuation/expansion projects.
Other possible investments could include expanded gas cycling, miscible/water
flood infill drilling, miscible injection supply increases to peripheral areas,
heavy oil tar recovery and development of the smaller reservoirs. While there is
no assurance that the Prudhoe Bay Unit working interest owners will make any
such investments they do regularly assess the technical and economic
attractiveness of implementing further projects to increase Prudhoe Bay Unit
proved reserves.
In the event of changes in the Company's current assumptions, oil and
condensate recoveries may be reduced from the current estimates, unless recovery
projects other than those included in the current estimates are implemented.
19
INDEPENDENT OIL AND GAS CONSULTANTS' REPORT
MILLER AND LENTS, LTD.
INTERNATIONAL OIL AND GAS CONSULTANTS
TWENTY-SEVENTH FLOOR
1100 LOUISIANA
HOUSTON, TEXAS 77002-5216
TELEPHONE 713 651-9455
TELEFAX 713 654-9914
email: mail@millerandlents.com
February 19, 2003
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street, Floor 21 West
New York, New York 10286
Re: Estimates of Proved Reserves, Future
Production Rates, and Future Net Revenues
for the BP Prudhoe Bay Royalty Trust
As of December 31, 2002
Gentlemen:
This letter report is a summary of investigations performed in accordance
with our engagement by you as described in Section 4.8(d) of the Overriding
Royalty Conveyance dated February 27, 1989, between BP Exploration (Alaska)
Inc., and The Standard Oil Company. The investigations included reviews of the
estimates of Proved Reserves and production rate forecasts of oil and condensate
made by BP Exploration (Alaska) Inc. attributable to the BP Prudhoe Bay Royalty
Trust as of December 31, 2002. Additionally, we reviewed calculations of the
resulting Estimated Future Net Revenues and Present Value of Estimated Future
Net Revenues attributable to the BP Prudhoe Bay Royalty Trust.
The estimates and calculations reviewed are summarized in the report
prepared by BP Exploration (Alaska) Inc. and transmitted with a cover letter
dated February 11, 2003 addressed to Ms. Marie E. Trimboli of The Bank of New
York and signed by Mr. Neil McCleary. Reviews were also performed by Miller and
Lents, Ltd. during this year or in previous years of (1) the procedures for
estimating and documenting Proved Reserves, (2) the estimates of in-place
reservoir volumes, (3) the estimates of recovery factors and production profiles
for the various areas, pay zones, projects, and recovery processes that are
included in the estimate of Proved Reserves, (4) the production strategy and
procedures for implementing that strategy, (5) the sufficiency of the data
available for making estimates of Proved Reserves and production profiles, and
(6) pertinent provisions of the Prudhoe Bay Unit Operating Agreement, the Issues
Resolution Agreement, the Overriding Royalty Conveyance, the Trust Conveyance,
the BP Prudhoe Bay Royalty Trust Agreement, and other related documents
referenced in the Form F-3 Registration Statement filed with the Securities and
Exchange Commission on August 7, 1989, by BP Exploration (Alaska) Inc.
20
Proved Reserves were estimated by BP Exploration (Alaska) Inc. in
accordance with the definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a). Estimated Future Net Revenues and Present Value of
Estimated Future Net Revenues are not intended and should not be interpreted to
represent fair market values for the estimated reserves.
The Prudhoe Bay (Permo-Triassic) Reservoir is defined in the Prudhoe Bay
Unit Operating Agreement. The Prudhoe Bay Unit is an oil and gas unit situated
on the North Slope of Alaska. The BP Prudhoe Bay Royalty Trust is entitled to a
royalty payment on 16.4246 percent of the first 90,000 barrels of the actual
average daily net production of oil and condensate for each calendar quarter
from the BP Exploration (Alaska) Inc. working interest as defined in the
Overriding Royalty Conveyance. The payment amount depends upon the Per Barrel
Royalty which in turn depends upon the West Texas Intermediate Price, the
Chargeable Costs, the Cost Adjustment Factor, and Production Taxes, all of which
are defined in the Overriding Royalty Conveyance. "Barrel" as used herein means
Stock Tank Barrel as defined in the Overriding Royalty Conveyance.
Our reviews do not constitute independent estimates of the reserves and
annual production rate forecasts for the areas, pay zones, projects, and
recovery processes examined. We relied upon the accuracy and completeness of
information provided by BP Exploration (Alaska) Inc. with respect to pertinent
ownership interests and various other historical, accounting, engineering, and
geological data.
As a result of our cumulative reviews, based on the foregoing, we conclude
that:
1. A large body of basic data and detailed analyses are available and
were used in making the estimates. In our judgment, the quantity and
quality of currently available data on reservoir boundaries, original
fluid contacts, and reservoir rock and fluid properties are sufficient
to indicate that any future revisions to the estimates of total
original in-place volumes should be minor. Furthermore, the data and
analyses on recovery factors and future production rates are
sufficient to support the Proved Reserves estimates.
2. The methods and procedures employed to accumulate and evaluate the
necessary information and to estimate, document, and reconcile
reserves, annual production rate forecasts, and future net revenues
are effective and are in accordance with generally accepted geological
and engineering practice in the petroleum industry.
3. Based on our limited independent tests of the computations of
reserves, production flowstreams, and future net revenues, such
computations were performed in accordance with the methods and
procedures described to us.
4. The estimated net remaining Proved Reserves attributable to the BP
Prudhoe Bay Royalty Trust as of December 31, 2002, of 85.82 million
barrels of oil and condensate are, in the aggregate, reasonable. Of
the 85.82 million barrels of total Proved Reserves, 85.79 million
barrels are Proved Developed Reserves, and 0.03 million barrels are
Proved Undeveloped Reserves.
21
5. Utilizing the specified procedures outlined in Financial Accounting
Standards Board Statement of Financial Accounting Standards No. 69, BP
Exploration (Alaska) Inc. calculated that as of December 31, 2002,
production of the Proved Reserves will result in Estimated Future Net
Revenues of $653.2 million and Present Value of Estimated Future Net
Revenues of $388.4 million to the BP Prudhoe Bay Royalty Trust. These
estimates are reasonable.
6. BP Exploration (Alaska) Inc. estimated that, as of December 31, 2002,
815.0 million barrels of Proved Reserves have been added to Current
Reserves. This estimate is reasonable. Current Reserves are defined in
the Overriding Royalty Conveyance as net Proved Reserves of 2,035.6
million barrels as of December 31, 1987. Net additions to Proved
Reserves after December 31, 1987 affect the Chargeable Costs that are
used to calculate the Per Barrel Royalty paid to the BP Prudhoe Bay
Royalty Trust.
7. The BP Exploration (Alaska) Inc. projection that its net production of
oil and condensate from Proved Reserves will continue at an average
rate exceeding 90,000 barrels per day until the year 2016 is
reasonable. As long as the Per Barrel Royalty has a positive value,
average daily production attributable to the BP Prudhoe Bay Royalty
Trust will remain constant until the net production falls below 90,000
barrels per day; thereafter, production attributable to the BP Prudhoe
Bay Royalty Trust will decline with the BP Exploration (Alaska) Inc.
production. However, the Per Barrel Royalty will not have a positive
value if the West Texas Intermediate Price is less than the sum of the
per barrel Chargeable Costs and per barrel Production Taxes,
appropriately adjusted in accordance with the Overriding Royalty
Conveyance. Under such circumstances, average daily production
attributable to the BP Prudhoe Bay Royalty Trust will have no value
and therefore will not contribute to the reserves regardless of BP
Exploration (Alaska) Inc.'s net production level.
8. Based on the West Texas Intermediate Price of $31.23 per barrel on
December 31, 2002, current Production Taxes, and the Chargeable Costs
adjusted as prescribed by the Overriding Royalty Conveyance, the
projection that royalty payments will continue through the year 2018
is reasonable. BP Exploration (Alaska) Inc. expects continued economic
production at a declining rate through the year 2030; however, for the
economic conditions and production forecast as of December 31, 2002,
the Per Barrel Royalty will be zero following the year 2018.
Therefore, no reserves are currently attributed to the BP Prudhoe Bay
Royalty Trust after that date.
9. Even if expected reservoir performance does not change, the estimated
reserves, economic life, and future revenues attributable to the BP
Prudhoe Bay Royalty Trust may change significantly in the future. This
may result from changes in the West Texas Intermediate Price or from
changes in other prescribed variables utilized in calculations defined
by the Overriding Royalty Conveyance.
Estimates of ultimate and remaining reserves and production scheduling
depend upon assumptions regarding expansion or implementation of alternative
projects or development programs and upon strategies for production
optimization. BP Exploration (Alaska) Inc. has continual reservoir management,
surveillance, and planning efforts dedicated to (1) gathering new information,
22
(2) improving the accuracy of its reserves and production capacity estimates,
(3) recognizing and exploiting new opportunities, (4) anticipating potential
problems and taking corrective actions, and (5) identifying, selecting, and
implementing optimum recovery program and cost reduction alternatives. Given
this significant effort and ever-changing economic conditions, estimates of
reserves and production profiles will change periodically.
The current estimate of Proved Reserves includes only those projects or
development programs that are deemed reasonably certain to be implemented, given
current economic and regulatory conditions. Future projects, development
programs, or operating strategies different from those assumed in the current
estimates may change future estimates and affect recoveries. However, because
several complementary and alternative projects are being considered for recovery
of the remaining oil in the reservoir, a decision not to implement a currently
planned project may allow scope expansion or implementation of another project,
thereby increasing the overall likelihood of recovering the reserves.
Future production rates will be controlled by facilities limitations and
upsets, well downtime, and the effectiveness of programs to optimize production
and costs. BP Exploration (Alaska) Inc. currently expects continued economic
production from the reservoir at a declining rate through the year 2030.
Additional drilling, workovers, facilities modifications, new recovery projects,
and programs for production enhancement and optimization are expected to
mitigate but not eliminate the decline in gross oil and condensate production
capacity.
In making its future production rate forecasts, BP Exploration (Alaska)
Inc. provided for normal downtime and planned facilities upsets. Although
allowances for unplanned upsets are also considered in the estimates, the
studies do not provide for any impediments to crude oil production as a
consequence of major disruptions.
Under current economic conditions, gas from the Alaskan North Slope, except
for minor volumes, cannot be marketed commercially. Oil and condensate
recoveries are expected to be greater as a result of continued reinjection of
produced gas than the recoveries would be if major volumes of produced gas were
being sold. No major gas sale is assumed in the current estimates. If major gas
sales are determined to be economically viable in the future, BP Exploration
(Alaska) Inc. estimates that such sales would not actually commence until seven
to nine years after such a determination. In the event that major gas sales are
initiated, ultimate oil and condensate recoveries may be reduced from the
current estimates unless recovery projects other than those included in the
current estimates are implemented.
Large volumes of natural gas liquids are likely to be produced and marketed
in the future whether or not major gas sales become viable. Natural gas liquids
reserves are not included in the estimates cited herein. The BP Prudhoe Bay
Royalty Trust is not entitled to royalty payments from production or sales of
natural gas or natural gas liquids.
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on accepted
standards of professional investigation but are subject to those generally
recognized uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies and market
conditions different from those reflected in this study or disruption of
23
existing transportation routes or facilities may cause the total quantity of oil
or condensate to be recovered, actual production rates, prices received, or
operating and capital costs to vary from those reviewed in this report.
Miller and Lents, Ltd., is an independent oil and gas consulting firm. None
of the principals of this firm have any direct financial interests in BP
Exploration (Alaska) Inc. or its parent or any related companies or in the BP
Prudhoe Bay Royalty Trust. Our fee is not contingent upon the results of our
work or report, and we have not performed other services for BP Exploration
(Alaska) Inc. or the BP Prudhoe Bay Royalty Trust that would affect our
objectivity.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ William P. Koza [SEAL]
------------------------------
William P. Koza
Vice President
WPK/hsd
24
INDUSTRY CONDITIONS AND REGULATIONS
The production of oil and gas in Alaska is affected by many state and
federal regulations with respect to allowable rates of production, marketing,
environmental matters and pricing. Future regulations could change allowable
rates of production or the manner in which oil and gas operations may be
lawfully conducted.
In general, the Company's oil and gas activities are subject to existing
federal, state and local laws and regulations relating to health, safety,
environmental quality and pollution control. The Company believes that the
equipment and facilities currently being used in its operations generally comply
with the applicable legislation and regulations. During the past few years,
numerous environmental laws and regulations have taken effect at the federal,
state and local levels. Oil and gas operations are subject to extensive federal
and state regulation and to interruption or termination by governmental
authorities due to ecological and other considerations and in certain
circumstances impose absolute liability upon lessees for the cost of cleaning up
pollutants and for pollution damages resulting from their operations. Although
the Company has advised that the existence of legislation and regulation has had
no material adverse effect on the Company's current method of operations,
existing and future legislation and regulations cannot be predicted.
CERTAIN TAX CONSIDERATIONS
The following is a summary of the principal tax consequences to Unit
holders resulting from the ownership and disposition of Units. The laws and
regulations affecting these matters are complex, and are subject to change by
future legislation or regulations or new interpretations by the Internal Revenue
Service, state taxing authorities or the courts. In addition, there may be
differences of opinion as to the applicability or interpretation of present tax
laws and regulations. The Company and the Trust have not requested any rulings
from the Internal Revenue Service with respect to the tax treatment of the
Units, and no assurance can be given that the Internal Revenue Service would
concur with the statements below.
Unit holders are urged to consult their tax advisors regarding the effects
on their specific tax situations of owning and disposing of Units.
Federal Income Tax
- ------------------
Classification of the Trust
The following discussion assumes that the Trust is properly classified as a
grantor trust under current law and is not an association taxable as a
corporation.
General Features of Grantor Trust Taxation
A grantor trust is not subject to tax, and its beneficiaries (the Unit
holders in the case of the Trust) are considered for tax purposes to own the
assets of the trust directly. The Trust pays no federal income tax but files an
information return reporting all items of income or deduction. If a court were
to hold that the Trust is an association taxable as a corporation, the Trust
would incur substantial income tax liabilities in addition to its other
expenses.
25
Taxation of Unit Holders
In computing his federal income tax liability, each Unit holder is required
to take into account his share of all items of Trust income, gain, loss,
deduction, credit and tax preference, based on the Unit holder's method of
accounting. Consequently, it is possible that in any year a Unit holder's share
of the taxable income of the Trust may exceed the cash actually distributed to
him in that year. For example, if the Trustee should establish a reserve or
borrow money to satisfy debts and liabilities of the Trust income used to
establish the reserve or to repay the loan must be reported by the Unit holder,
even though the income is not distributed to the Unit holder.
The Trust makes quarterly distributions to Unit holders of record on each
Quarterly Record Date. The terms of the Trust Agreement seek to assure to the
extent practicable that income, expenses and deductions attributable to each
distribution are reportable by the Unit holder who receives the distribution.
The Trust allocates income and deductions to Unit holders based on record
ownership at Quarterly Record Dates. It is not known whether the Internal
Revenue Service will accept the allocation based on this method.
Depletion Deductions
The owner of an economic interest in producing oil and gas properties is
entitled to deduct an allowance for the greater of cost depletion or (if
otherwise allowable) percentage depletion on each such property. A Unit holder's
deduction for cost depletion in any year is calculated by multiplying the
holder's adjusted tax basis in his Units (generally his cost less prior
depletion deductions) by Royalty Production during the year and dividing that
product by the sum of Royalty Production during the year and estimated remaining
Royalty Production as of the end of the year. The allowance for percentage
depletion generally does not apply to interests in proven oil and gas properties
that were transferred after December 31, 1974 and prior to October 12, 1990. The
Omnibus Budget Reconciliation Act of 1990 repealed this rule for transfers
occurring on or after October 12, 1990. Unit holders who acquired their Units on
or after that date may be permitted to deduct an allowance for percentage
depletion if such deduction would otherwise exceed the allowable deduction for
cost depletion. In order to take percentage depletion, a Unit holder must
qualify for the "independent producer" exemption contained in section 613A(c) of
the Internal Revenue Code of 1986. Percentage depletion is based on the Unit
holder's gross income from the Trust rather than on his adjusted basis in his
Units. Any deduction for cost depletion or percentage depletion allowable to a
Unit holder reduces his adjusted basis in his Units for purposes of computing
subsequent depletion or gain or loss on any subsequent disposition of Units.
Unit holders must maintain records of their adjusted basis in their Units,
make adjustments for depletion deductions to such basis, and use the adjusted
basis for the computation of gain or loss on the disposition of the Units.
Taxation of Foreign Unit Holders
- --------------------------------
Generally, a holder of Units who is a nonresident alien individual or which
is a foreign corporation (a "Foreign Taxpayer") is subject to tax of on the
gross income produced by the Royalty Interest at a rate equal to 30 percent (or
at a lower treaty rate, if applicable). This tax is withheld by the Trustee and
26
remitted directly to the United States Treasury. A Foreign Taxpayer may elect to
treat the income from the Royalty Interest as effectively connected with the
conduct of a United States trade or business under Internal Revenue Code section
871 or section 882, or pursuant to any similar provisions of applicable
treaties. If a Foreign Taxpayer makes this election, it is entitled to claim all
deductions with respect to such income, but a United States federal income tax
return must be filed to claim such deductions. This election once made is
irrevocable unless an applicable treaty allows the election to be made annually.
Section 897 of the Internal Revenue Code and the Treasury Regulations
thereunder treat the Trust as if it were a United States real property holding
corporation. Foreign holders owning more than five percent of the outstanding
Units are subject to United States federal income tax on the gain on the
disposition of their Units. Foreign Unit holders owning less than five percent
of the outstanding Units are not subject to United States federal income tax on
the gain on the disposition of their Units, unless they have elected under
Internal Revenue Code section 871 or section 872 to treat the income from the
Royalty Interest as effectively connected with the conduct of a United States
trade or business.
If a Foreign person is a corporation which made an election under Internal
Revenue Code section 882(d), the corporation would also be subject to a 30
percent tax under Internal Revenue Code section 884. This tax is imposed on U.S.
branch profits of a foreign corporation that are not reinvested in the U.S.
trade or business. This tax is in addition to the tax on effectively connected
income. The branch profits tax may be either reduced or eliminated by treaty.
Sale of Units
- -------------
Generally, a Unit holder will realize gain or loss on the sale or exchange
of his Units measured by the difference between the amount realized on the sale
or exchange and his adjusted basis for such Units. Gain on the sale of Units by
a holder that is not a dealer with respect to such Units will generally be
treated as capital gain. However, pursuant to Internal Revenue Code section
1254, certain depletion deductions claimed with respect to the Units must be
recaptured as ordinary income upon sale or disposition of such interest.
Backup Withholding
- ------------------
A payor must withhold 31 percent of any reportable payment if the payee
fails to furnish his taxpayer identification number ("TIN") to the payor in the
required manner or if the Secretary of the Treasury notifies the payor that the
TIN furnished by the payee is incorrect. Unit holders will avoid backup
withholding by furnishing their correct TINs to the Trustee in the form required
by law.
State Income Taxes
- ------------------
Unit holders may be required to report their share of income from the Trust
to their state of residence or commercial domicile. However, only corporate Unit
holders will need to report their share of income to the State of Alaska. Alaska
does not impose an income tax on individuals or estates and trusts. All Trust
income is Alaska source income to corporate Unit holders and should be reported
accordingly.
27
ITEM 2. PROPERTIES
Reference is made to Item 1 for the information required by this item.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS
None.
28
PART II
ITEM 5. MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS
The Units are listed and traded on the New York Stock Exchange under the
symbol BPT. The following table shows the high and low sales prices per Unit on
the New York Stock Exchange and the cash distributions paid per Unit, for each
calendar quarter in the two years ended December 31, 2002.
Distributions
High Low Per Unit
---- --- --------
2001:
First Quarter $10.63 $ 8.56 $0.924
Second Quarter 12.44 8.31 0.662
Third Quarter 14.94 10.94 0.611
Fourth Quarter 15.41 11.50 0.573
2002:
First Quarter $15.01 $10.98 $0.216
Second Quarter 14.37 11.20 0.230
Third Quarter 14.49 10.70 0.476
Fourth Quarter 15.10 12.50 0.585
As of January 23, 2003, 21,400,000 Units were outstanding and were held by
928 holders of record.
Future payments of cash distributions are dependent on such factors as the
prevailing WTI Price, the relationship of the rate of change in the WTI Price to
the rate of change in the Consumer Price Index, the Chargeable Costs, the rates
of Production Taxes prevailing from time to time, and the actual production from
the Prudhoe Bay Unit. See "THE ROYALTY INTEREST" in Item 1.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents in summary form selected financial
information regarding the Trust.
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(In thousands, except per Unit amounts)
Royalty revenues $ 33,061 59,934 65,026 13,443 15,163
Interest income $ 23 70 92 60 17
Trust administration expenses $ 822 724 732 798 614
Expenses reserve $ -- -- 500 500 --
----------- ----------- ----------- ----------- -----------
Cash earnings $ 32,262 59,280 63,886 12,205 14,566
Cash distributions $ 32,246 59,319 63,838 12,205 14,566
Cash distributions per unit $ 1.507 2.772 2.983 0.570 0.681
Units outstanding 21,400,000 21,400,000 21,400,000 21,400,000 21,400,000
29
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Cautionary Statement
- --------------------
The Trustee, its officers or its agents on behalf of the Trustee may, from
time to time, make forward-looking statements (other than statements of
historical fact). When used herein, the words "anticipates," "expects,"
"believes," "intends" or "projects" and similar expressions are intended to
identify forward-looking statements. To the extent that any forward-looking
statements are made, the Trustee is unable to predict future changes in oil
prices, oil production levels, economic activity, legislation and regulation,
and certain changes in expenses of the Trust. In addition, the Trust's future
results of operations and other forward looking statements contained in this
item and elsewhere in this report involve a number of risks and uncertainties.
As a result of variations in such factors, actual results may differ materially
from any forward looking statements. Some of these factors are described below.
The Trustee disclaims any obligation to update forward looking statements and
all such forward-looking statements in this document are expressly qualified in
their entirety by the cautionary statements in this paragraph.
Liquidity and Capital Resources
- -------------------------------
The Trust is a passive entity, and the Trustee's activities are limited to
collecting and distributing the revenues from the Royalty Interest and paying
liabilities and expenses of the Trust. Generally, the Trust has no source of
liquidity and no capital resources other than the revenue attributable to the
Royalty Interest that it receives from time to time. See the discussion under
"THE ROYALTY INTEREST" in Item 1 for a description of the calculation of the Per
Barrel Royalty, and the discussion under "THE PRUDHOE BAY UNIT - Reserve
Estimates" and "INDEPENDENT OIL AND GAS CONSULTANTS' REPORT" in Item 1 for
information concerning the estimated future net revenues of the Trust. However,
the Trustee does have a limited power to borrow, establish a cash reserve, or
dispose of all or part of the Trust Estate, under limited circumstances pursuant
to the terms of the Trust Agreement. See the discussion under "BUSINESS - The
Trust" in Item 1.
The decline in WTI Prices during the fourth quarter of 1998 and the first
quarter of 1999 resulted in the Trust not receiving quarterly distributions
during the first and second quarters of 1999. See "THE ROYALTY INTEREST - Per
Barrel Royalty Calculations. Upon the increase in the WTI Price in the second
quarter of 1999 and the resumption of distributions in the third quarter of
1999, the Trustee established a cash reserve to provide liquidity to the Trust
during any future periods in which the Trust does not receive a distribution.
The Trustee set aside $1,000,000 in the cash reserve account, from quarterly
distributions received by the Trust, in four equal quarterly installments
commencing with the July 1999 distribution. The Trustee will draw funds from the
cash reserve account during any quarter in which the quarterly distribution
received by the Trust does not exceed the liabilities and expenses of the Trust,
and will replenish the reserve from future quarterly distributions, if any.
Amounts set aside for the cash reserve are being invested in U.S.
government or agency securities secured by the full faith and credit of the
United States. Interest income received by the Trust from the investment of the
reserve fund is added to the distributions received from the Company and paid to
the holders of Units on each Quarterly Record Date. The Trustee anticipates that
it will keep this cash reserve program in place until termination of the Trust.
30
As discussed under "BUSINESS - Certain Tax Considerations", amounts
received by the Trust as quarterly distributions (and earnings on investment of
the cash reserve) are income to the holders of the Units for the taxable year in
which such amounts are received by the Trust and must be reported by the holders
of the Units even if a portion of such amounts are used to repay borrowings by
the Trust or add to the cash reserve and are not received by the holders of the
Units.
Results of Operations
- ---------------------
Relatively modest changes in oil prices will significantly affect the
Trust's revenues and results of operations. Crude oil prices are subject to
significant changes in response to fluctuations in the domestic and world supply
and demand and other market conditions as well as the world political situation
as it affects OPEC and other producing countries. The effect of changing
economic conditions on the demand and supply for energy throughout the world and
future prices of oil cannot be accurately projected.
Royalty revenues are generally received on the Quarterly Record Date
(generally the fifteenth day of the month) following the end of the calendar
quarter in which the related Royalty Production occurred. The Trustee, to the
extent possible, pays all expenses of the Trust for each quarter on the
Quarterly Record Date on which the revenues for the quarter are received. For
the statement of cash earnings and distributions, revenues and Trust expenses
are recorded on a cash basis and, as a result, distributions to Unit holders in
each calendar year ending December 31 are attributable to the Company's
operations during the twelve-month period ended on the preceding September 30.
As long as the Company's average daily net production from the Prudhoe Bay
Unit exceeds 90,000 Barrels, which the Company currently projects will continue
until the year 2018, the only factors affecting the Trust's revenues and
distributions to Unit holders are changes in WTI Prices, scheduled annual
increases in Chargeable Costs, changes in the Consumer Price Index, changes in
Production Taxes, changes in the expenses of the Trust, contributions to the
cash reserve and interest earned on the cash reserve.
During the year 2002 and the period of 2003 up to the date of this report,
the WTI Prices have been above the level necessary for the Trust to receive a
Per Barrel Royalty. Whether the Trust will be entitled to future distributions
during the remainder of 2003 will depend on WTI Prices prevailing during the
remainder of the year.
2002 compared to 2001
- ---------------------
Royalty revenues and cash distributions in calendar 2002 decreased by
approximately 44.8% and 45.6%, respectively, from 2001. The decline was due
principally to a sharp drop in average WTI Prices during the fourth quarter of
2001 and the first quarter of 2002. Although WTI prices recovered later in 2002
to approximately the same levels as at the beginning of 2001, overall the
average WTI Price for the twelve months ended September 30, 2002 (on which
calendar 2002 cash basis revenues were based) was approximately 16% lower than
for the immediately preceding twelve-month period. Royalty revenues also were
negatively affected by the scheduled increase in Chargeable Costs from $10.75 to
$11.25 in the first quarter of 2002; however this impact was somewhat offset by
Production Taxes, which declined approximately 21% during the twelve-month
period ended September 30, 2002 from the preceding period as a consequence of
the decreases in average WTI Prices. The Cost Adjustment Factor had a neutral
effect during 2002, as it remained substantially constant on average from the
previous year.
31
2001 compared to 2000
- ---------------------
Royalty revenues and cash distributions in 2001 decreased by approximately
7.8% and 7.1%, respectively, from 2000. Although the average WTI Price during
the 12 months ended September 30, 2001 increased by about 1.4% from the average
price during the same period in 2000, the increase was offset by an increase of
approximately 9.7% in Adjusted Chargeable Costs, primarily as a result of the
scheduled increase in Chargeable Costs from $10.00 per Barrel to $10.75 per
Barrel in the first quarter of 2001 and continued increases in the Cost
Adjustment Factor (see "THE ROYALTY INTEREST-Per Barrel Royalty Calculations" in
Item 1).
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BP PRUDHOE BAY ROYALTY TRUST
INDEX TO FINANCIAL STATEMENTS
Page
----
Independent Auditors' Report..................................................33
Statements of Assets, Liabilities and Trust Corpus
as of December 31, 2002 and 2001............................................34
Statement of Cash Earnings and Distributions for the years ended
December 31, 2002, 2001 and 2000............................................35
Statements of Changes in Trust Corpus for the years ended
December 31 2002, 2001 and 2000.............................................36
Notes to Financial Statements.................................................37
32
INDEPENDENT AUDITORS' REPORT
Trustee and Holders of Trust Units of
BP Prudhoe Bay Royalty Trust:
We have audited the accompanying statements of assets, liabilities and
trust corpus of BP Prudhoe Bay Royalty Trust as of December 31, 2002 and 2001,
and the related statements of cash earnings and distributions, and changes in
trust corpus for each of the years in the three-year period ended December 31,
2002. These financial statements are the responsibility of the Trustee. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by the Trustee, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As described in note 2, these financial statements have been prepared on a
modified basis of cash receipts and disbursements, which is a comprehensive
basis of accounting other than accounting principles generally accepted in the
United States of America.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of BP Prudhoe
Bay Royalty Trust as of December 31, 2002 and 2001, and its cash earnings and
distributions and its changes in trust corpus for each of the years in the
three-year period ended December 31, 2002, on the basis of accounting described
in note 2.
/s/KPMG LLP
KPMG LLP
New York, New York
March 18, 2003
33
BP PRUDHOE BAY ROYALTY TRUST
Statement of Assets, Liabilities and Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements)
(In thousands)
December 31, December 31,
2002 2001
---- ----
ASSETS
Royalty Interest, net (notes 1, 2 and 3) $ 16,068 $ 18,077
Cash and cash equivalents (note 2) 1,025 1,009
--------- ---------
Total assets $ 17,093 $ 19,086
========= =========
LIABILITIES AND TRUST CORPUS
Accrued expenses $ 595 $ 522
Trust Corpus (40,000,000 units of beneficial
interest authorized, 21,400,000 units issued
and outstanding) 16,498 18,564
--------- ---------
Total liabilities and trust corpus $ 17,093 $ 19,086
========= =========
See accompanying notes to financial statements.
34
BP PRUDHOE BAY ROYALTY TRUST
Statements of Cash Earnings and Distributions
(Prepared on a modified basis of cash receipts and disbursements)
(In thousands, except unit data)
For the Years Ended December 31,
2002 2001 2000
---- ---- ----
Royalty revenues $ 33,061 $ 59,934 $ 65,026
Interest income 23 70 92
Less: Trust administrative expenses (822) (724) (732)
Expense reserve -- -- (500)
----------- ----------- -----------
Cash earnings $ 32,262 $ 59,280 $ 63,886
=========== =========== ===========
Cash distributions $ 32,246 $ 59,319 $ 63,838
=========== =========== ===========
Cash distributions per unit $ 1.507 $ 2.772 $ 2.983
=========== =========== ===========
Units outstanding 21,400,000 21,400,000 21,400,000
=========== =========== ===========
See accompanying notes to financial statements.
35
BP PRUDHOE BAY ROYALTY TRUST
Statements of Changes in Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements)
(In thousands)
For the Years Ended December 31,
2002 2001 2000
---- ---- ----
Trust Corpus at beginning of year $ 18,564 $ 20,669 $ 22,626
Cash earnings 32,262 59,280 63,886
Increase in cash reserve -- -- 500
Decrease (increase) in accrued expenses (73) (58) 6
Cash distributions (32,246) (59,319) (63,838)
Amortization of Royalty Interest (2,009) (2,008) (2,511)
---------- ---------- ----------
Trust Corpus at end of year $ 16,498 $ 18,564 $ 20,669
========== ========== ==========
See accompanying notes to financial statements.
36
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2002, 2001 and 2000
(1) FORMATION OF THE TRUST AND ORGANIZATION
BP Prudhoe Bay Royalty Trust (the "Trust"), a grantor trust, was created as
a Delaware business trust pursuant to a Trust Agreement dated February 28,
1989 among the Standard Oil Company ("Standard Oil"), BP Exploration
(Alaska) Inc. (the "Company"), The Bank of New York (The "Trustee") and The
Bank of New York (Delaware), as co-trustee. Standard Oil and the Company
are indirect wholly-owned subsidiaries of BP p.l.c. ("BP").
Effective January 1, 2000, the Company and all other Prudhoe Bay working
interest owners cross-assigned interests in the Prudhoe Bay Field pursuant
to the Prudhoe Bay Unit Alignment Agreement. The Company retained all
rights, obligations, and liabilities associated with the Trust. This
transaction is not expected to have a material effect on the Trust's
operation.
On February 28, 1989, Standard Oil conveyed an overriding royalty interest
(the "Royalty Interest") to the Trust. The Trust was formed for the sole
purpose of owning and administering the Royalty Interest. The Royalty
Interest represents the right to receive, effective February 28, 1989, a
per barrel royalty (the "Per Barrel Royalty") of 16.4246% on the lesser of
(a) the first 90,000 barrels of the average actual daily net production of
oil and condensate per quarter or (b) the average actual daily net
production of oil and condensate per quarter from the Company's working
interest in the Prudhoe Bay Field (the "Field") as of February 28, 1989,
located on the North Slope of Alaska. Trust Unit holders will remain
subject at all times to the risk that production will be interrupted or
discontinued or fall, on average, below 90,000 barrels per day in any
quarter. BP has guaranteed the performance of the Company of its payment
obligations with respect to the Royalty Interest.
The trustees of the Trust are The Bank of New York, a New York banking
corporation, and The Bank of New York (Delaware), a Delaware banking
corporation. The Bank of New York (Delaware) serves as co-trustee in order
to satisfy certain requirements of the Delaware Trust Act. The Bank of New
York alone is able to exercise the rights and powers granted to the Trustee
in the Trust Agreement.
The Per Barrel Royalty in effect for any day is equal to the price of West
Texas Intermediate crude oil (the "WTI Price") for that day less scheduled
Chargeable Costs (adjusted for inflation) and Production Taxes (based on
statutory rates then in existence). For years subsequent to 2006,
Chargeable Costs will be reduced up to a maximum amount of $1.20 per barrel
in each year if additions to the Field's proved reserves do not meet
certain specific levels.
The Trust is passive, with the Trustee having only such powers as are
necessary for the collection and distribution of revenues, the payment of
Trust liabilities, and the protection of the Royalty Interest. The Trustee,
subject to certain conditions, is obligated to establish cash reserves and
borrow funds to pay liabilities of the Trust when they become due. The
Trustee may sell Trust properties only (a) as authorized by a vote of the
Trust Unit Holders, (b) when necessary to provide for the payment of
37
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2002, 2001 and 2000 (continued)
specific liabilities of the Trust then due (subject to certain conditions)
or (c) upon termination of the Trust. Each Trust Unit issued and
outstanding represents an equal undivided share of beneficial interest in
the Trust. Royalty payments are received by the Trust and distributed to
Trust Unit holders, net of Trust expenses, in the month succeeding the end
of each calendar quarter. The Trust will terminate upon the first to occur
of the following events:
a. On or prior to December 31, 2010: upon a vote of Trust Unit holders of
not less than 70% of the outstanding Trust Units.
b. After December 31, 2010: (i) upon a vote of Trust Unit holders of not
less than 60% of the outstanding Trust Units, or (ii) at such time the
net revenues from the Royalty Interest for two successive years
commencing after 2010 are less than $1,000,000 per year (unless the
net revenues during such period are materially and adversely affected
by certain events).
In order to ensure the Trust has the ability to pay future expenses, the
Trust established a cash reserve account which the Trustee believes is
sufficient to pay approximately one year's current and expected liabilities
and expenses of the Trust.
(2) BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on a modified cash basis
and reflect the Trust's assets, liabilities, Corpus, earnings, and
distributions, as follows:
a. Revenues are recorded when received (generally within 15 days of the
end of the preceding quarter) and distributions to Trust Unit holders
are recorded when paid.
b. Trust expenses (which include accounting, engineering, legal, and
other professional fees, trustees' fees, and out-of-pocket expenses)
are recorded on an accrual basis.
c. Amortization of the Royalty Interest is calculated based on the units
of production attributable to the Trust over the production of
estimated proved reserves attributable to the Trust at the beginning
of the fiscal year (approximately 43,200,000, 90,700,000 and
93,600,000 barrels of estimated proved reserves were used to calculate
the amortization of the Royalty Interest for the years ended December
31, 2002, 2001 and 2000, respectively). Such amortization is charged
directly to the Trust Corpus, and does not affect cash earnings. The
daily rate for amortization per net equivalent barrel of oil for the
38
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2002, 2001 and 2000 (continued)
years ended December 31, 2002, 2001 and 2000 was $0.37, $0.37 and
$0.47, respectively. The Trust evaluates impairment of the Royalty
Interest by comparing the undiscounted cash flows expected to be
realized from the Royalty Interest to the carrying value, pursuant to
Statement of Financial Accounting Standards No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). If the
expected future undiscounted cash flows are less than the carrying
value, the Trust recognizes an impairment loss for the difference
between the carrying value and the estimated fair value of the Royalty
Interest (see note 3).
While these statements differ from financial statements prepared in
accordance with accounting principles generally accepted in the United
States of America, the cash basis of reporting revenues and distributions
is considered to be the most meaningful because quarterly distributions to
the Unit holders are based on net cash receipts.
As of December 31, 2002 and 2001, cash equivalents which represent the cash
reserve consist of US treasury bills with an initial term of less than
three months.
Estimates and assumptions are required to be made regarding assets,
liabilities and changes in Trust Corpus resulting from operations when
financial statements are prepared. Changes in the economic environment,
financial markets and any other parameters used in determining these
estimates could cause actual results to differ.
(3) ROYALTY INTEREST
The Royalty Interest is comprised of the following at December 31, 2002 and
2001 (in thousands):
December 31,
--------------------
2002 2001
---- ----
Royalty Interest $ 535,000 $ 535,000
Less: Accumulated amortization (345,414) (343,405)
Impairment write-down (173,518) (173,518)
---------- ----------
$ 16,068 $ 18,077
========== ==========
(4) INCOME TAXES
The Trust files its federal tax return as a grantor trust subject to the
provisions of subpart E of Part I of Subchapter J of the Internal Revenue
Code of 1986, as amended, rather than as an association taxable as a
corporation. The Unit holders are treated as the owners of Trust income and
Corpus, and the entire taxable income of the Trust is reportable by the
Unit holders on their respective tax returns.
39
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2002, 2001 and 2000 (continued)
If the Trust were determined to be an association taxable as a corporation,
it would be treated as an entity taxable as a corporation on the taxable
income from the Royalty Interest, the Trust Unit holders would be treated
as shareholders, and distributions to Trust Unit holders would not be
deductible in computing the Trust's tax liability as an association.
(5) SUMMARY OF QUARTERLY RESULTS (UNAUDITED)
A summary of selected quarterly financial information for the years ended
December 31, 2002, 2001, and 2000 is as follows (in thousands, except unit
data):
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
2002
Royalty revenues $ 4,841 5,205 10,314 12,701
Interest income 7 5 6 5
Trust administrative expenses (216) (298) (130) (178)
--------- --------- --------- ---------
Cash earnings 4,632 4,912 10,190 12,528
Cash distributions 4,621 4,931 10,185 12,509
Cash distributions per unit 0.216 0.230 0.476 0.585
2001
Royalty revenues $ 19,932 14,418 13,269 12,315
Interest income 19 17 23 11
Trust administrative expenses (158) (253) (269) (44)
--------- --------- --------- ---------
Cash earnings 19,793 14,182 13,023 12,282
Cash distributions 19,777 14,167 13,096 12,279
Cash distributions per unit 0.924 0.662 0.612 0.574
2000
Royalty revenues $ 12,105 16,841 16,425 19,655
Interest income -- 16 11 65
Trust administrative expenses (164) (274) (232) (62)
Expenses reserve (250) (250) -- --
--------- --------- --------- ---------
Cash earnings 11,691 16,333 16,204 19,658
Cash distributions 11,691 16,333 16,204 19,610
Cash distributions per unit 0.546 0.763 0.757 0.917
40
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2002, 2001 and 2000 (continued)
(6) SUPPLEMENTAL RESERVE INFORMATION AND STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOW RELATING TO PROVED RESERVES (UNAUDITED)
Pursuant to Statement of Financial Accounting Standards No. 69,
"Disclosures About Oil and Gas Producing Activities" ("FASB 69"), the Trust
is required to include in its financial statements supplementary
information regarding estimates of quantities of proved reserves
attributable to the Trust and future net cash flows.
Estimates of proved reserves are inherently imprecise and subjective and
are revised over time as additional data becomes available. Such revisions
may often be substantial. Information regarding estimates of proved
reserves attributable to the combined interests of the Company and the
Trust were based on Company-prepared reserve estimates. The Company's
reserve estimates are believed to be reasonable and consistent with
presently known physical data concerning the size and character of the
Field.
There is no precise method of allocating estimates of physical quantities
of reserve volumes between the Company and the Trust, since the Royalty
Interest is not a working interest and the Trust does not own and is not
entitled to receive any specific volume of reserves from the Field. Reserve
volumes attributable to the Trust were estimated by allocating to the Trust
its share of estimated future production from the Field, based on the WTI
Price on December 31, 2002 ($31.23 per barrel), December 31, 2001 ($19.78
per barrel), and December 31, 2000 ($26.83 per barrel.) Because the reserve
volumes attributable to the Trust are estimated using an allocation of
reserve volumes based on the estimated future production and on the current
WTI Price, a change in the timing of estimated production or a change in
the WTI price will result in a change in the Trust's estimated reserve
volumes. Therefore, the estimated reserve volumes attributable to the Trust
will vary if different production estimates and prices are used.
In addition to production estimates and prices, reserve volumes
attributable to the Trust are affected by the amount of Chargeable Costs
that will be deducted in determining the Per Barrel Royalty. The Royalty
Interest includes a provision under which, in years subsequent to 2006, if
additions to the Field's proved reserves from January 1, 1988 (after
certain adjustments) do not meet certain specified levels, Chargeable Costs
will be reduced up to a maximum amount of $1.20 per barrel in each year.
Under the provisions of FASB 69, no consideration can be given to reserves
not considered proved at the present time. Accordingly, in estimating the
reserve volumes attributable to the Trust, Chargeable Costs were reduced by
the maximum amount in years subsequent to 1998, after considering the
amount of reserves that have been added to the Field's proved reserves from
January 1, 1988.
Net proved reserves of oil and condensate attributable to the Trust as of
December 31, 2002, 2001 and 2000, based on the Company's latest reserve
estimate at such time, the WTI Prices on December 31, 2002, 2001 and 2000
and a reduction in Chargeable Costs in years subsequent to 1998, were
estimated to be 86 million, 43 million and 91 million barrels, respectively
(of which 86 million, 43 million, and 84 million barrels, respectively, are
proved developed).
The standardized measure of discounted future net cash flow relating to
proved reserves disclosure required by FASB 69 assigns monetary amounts to
41
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2002, 2001 and 2000 (continued)
proved reserves based on current prices. This discounted future net cash
flow should not be construed as the current market value of the Royalty
Interest. A market valuation determination would include, among other
things, anticipated price increases and the value of additional reserves
not considered proved at the present time or reserves that may be produced
after the currently anticipated end of field life. At December 31, 2002,
2001 and 2000, the standardized measure of discounted future net cash flow
relating to proved reserves attributable to the Trust (estimated in
accordance with the provisions of FASB 69), based on the WTI Prices on
those dates of $31.23, $19.78 and $26.83, respectively, were as follows (in
thousands):
December 31, December 31, December 31,
2002 2001 2000
---- ---- ----
Future net cash flows $ 653,236 $ 64,584 $ 520,980
10% annual discount for estimated
timing of cash flows (264,803) (17,543) (214,733)
--------- -------- ---------
Standardized measure of
discounted future net cash
flow relating to proved
reserves (a) $ 388,433 $ 47,041 $ 306,247
========= ======== =========
(a) The standardized measure of discounted future net cash flow relating
to proved reserves, estimated without reducing Chargeable Costs in
years subsequent to 1998, would be $388,433,000, $47,041,000 and
$306,247,000 at December 31, 2002, 2001 and 2000, respectively. The
following are the principal sources of the change in the standardized
measure of discounted future net cash flows (in thousands):
2002 2001 2000
---- ---- ----
Revisions of prior estimates:
Reserve volumes $ 90,906 $ 47,566 $ 2,913
WTI price 350,099 (314,380) 80,047
Chargeable costs - inflation (11,059) (24,397) (26,302)
Production taxes (51,886) 47,995 (10,571)
Other (186) 956 (2,187)
---------- ---------- ----------
377,874 (242,260) 43,900
Royalty income received (b) (40,759) (44,842) (72,853)
Accretion of discount 4,277 27,896 30,473
---------- ---------- ----------
Net increase (decrease) during the year $ 341,392 $ (259,206) $ 1,520
========== ========== ==========
42
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
December 31, 2002, 2001 and 2000 (continued)
(b) Royalty income received for 2002, 2001 and 2000 includes the
following:
Period October 1, 2002 through December 31, 2002 $ 12,538
Period October 1, 2001 through December 31, 2001 $ 4,840
Period October 1, 2000 through December 31, 2000 $ 19,932
The above royalty income was received by the Trust in January 2003, 2002
and 2001, respectively.
The changes in quantities of proved oil and condensate were as follows
(thousands of barrels):
Estimated net proved reserves of oil
and condensate at December 31, 2000 90,711
Production (5,395)
Reserve estimate revisions 1,055
Change caused by prices/costs (43,178)
------
Estimated net proved reserves of oil
and condensate at December 31, 2001 43,193
Production (5,395)
Reserve estimate revisions --
Change caused by prices/costs 48,020
------
Estimated net proved reserves of oil
and condensate at December 31, 2002 85,818
======
Proved reserves:
December 31, 2000 90,711
======
December 31, 2001 43,193
======
December 31, 2002 85,818
======
43
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Trust has no directors or executive officers. The Trustee has only such
rights and powers as are necessary to achieve the purposes of the Trust.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable.
ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Unit Ownership of Certain Beneficial Owners
- -------------------------------------------
As of March 28, 2003, there were no persons known to the Trustee to be the
beneficial owners of more than five percent of the Units.
Unit Ownership of Management
- ----------------------------
Neither the Company, Standard Oil, nor BP owns any Units. No Units are
owned by The Bank of New York, as Trustee or in its individual capacity, or by
The Bank of New York (Delaware), as co-trustee or in its individual capacity.
Changes in Control
- ------------------
The Trustee knows of no arrangement, including the pledge of Units, the
operation of which may at a subsequent date result in a change in control of the
Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
ITEM 14. CONTROLS AND PROCEDURES
Within 90 days prior to the date of this report (the "Evaluation Date") the
officer of the Trustee signing this report carried out an evaluation of the
effectiveness of the design and operation of the Trustee's disclosure controls
and procedures for the Trust pursuant to Rule 13a-14 under the Securities
Exchange Act of 1934 (the "Exchange Act"). Based on the foregoing that officer
concluded that the disclosure controls and procedures for the Trust are
effective in timely alerting the responsible officers of the Trustee to material
information relating to the Trust required to be included in the Trust's
Exchange Act reports. There have been no significant changes in the Trustee's
internal controls or in other factors which could significantly affect internal
controls subsequent to the date the Trustee carried out its evaluation.
44
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) FINANCIAL STATEMENTS
The following financial statements of the Trust are included in Part II,
Item 8:
Independent Auditors' Report
Statements of Assets, Liabilities and Trust Corpus as of December 31,
2002 and 2001
Statements of Cash Earnings and Distributions for the years ended
December 31, 2002, 2001 and 2000
Statements of Changes in Trust Corpus for the years ended December 31,
2002, 2001 and 2000
Notes to Financial Statements
(b) FINANCIAL STATEMENT SCHEDULES
All financial statement schedules have been omitted because they are either
not applicable, not required or the information is set forth in the financial
statements or notes thereto.
(c) EXHIBITS
4.1 BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among
The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of
New York, Trustee, and F. James Hutchinson, Co-Trustee.
4.2 Overriding Royalty Conveyance dated February 27, 1989 between BP
Exploration (Alaska) Inc. and The Standard Oil Company.
4.3 Trust Conveyance dated February 28, 1989 between The Standard Oil
Company and BP Prudhoe Bay Royalty Trust.
4.4 Support Agreement dated as of February 28, 1989 among The British
Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard
Oil Company and BP Prudhoe Bay Royalty Trust.
99 Sarbanes-Oxley Section 906 Certification, dated March 31, 2003.
(d) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the quarter ended December 31, 2002.
45
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
BP PRUDHOE BAY ROYALTY TRUST
By: THE BANK OF NEW YORK, as Trustee
By: /s/ Marie Trimboli
----------------------
Marie Trimboli
Assistant Vice President
March 31, 2003
The Registrant is a trust and has no officers, directors, or persons
performing similar functions. No additional signatures are available and none
have been provided.
46
INDEX TO EXHIBITS
Exhibit No. Description
----------- -----------
4.1* BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among
The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of
New York, Trustee, and F. James Hutchinson, Co-Trustee.
4.2* Overriding Royalty Conveyance dated February 27, 1989 between BP
Exploration (Alaska) Inc. and The Standard Oil Company.
4.3* Trust Conveyance dated February 28, 1989 between The Standard Oil
Company and BP Prudhoe Bay Royalty Trust.
4.4* Support Agreement dated as of February 28, 1989 among The British
Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard
Oil Company and BP Prudhoe Bay Royalty Trust.
99 Sarbanes-Oxley Section 906 Certification, dated March 31, 2003. Filed
herewith.
- --------------------
* Incorporated by reference to the correspondingly numbered exhibit to the
Registrant's Annual Report on Form 10-K for the fiscal year ended December 31,
1996 (File No. 1-10243).
1 As used in the overriding royalty conveyance and this report, (a) the term
"Barrel" is a unit of measure equal to 42 United States gallons corrected to 60
degrees Fahrenheit temperature and with deductions for sediment and water
content, and (b) the term "Stock Tank Barrel" or "STB" refers to a Barrel of
stabilized oil or condensate at a temperature of 60 degrees Fahrenheit and
sea-level atmospheric pressure (14.7 pounds per square inch absolute).