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, 2000
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 1-10243
BP PRUDHOE BAY ROYALTY TRUST
(Exact name of registrant as specified in its charter)
DELAWARE 13-6943724
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
THE BANK OF NEW YORK, TRUSTEE
101 BARCLAY STREET, FLOOR 21 WEST
NEW YORK, NEW YORK 10286
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (212) 815-5092
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
------------------- -----------------------------------------
UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant: (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
As of March 29, 2001, 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
$343,684,000.
Documents Incorporated by Reference: None
TABLE OF CONTENTS
PART I
ITEM 1. BUSINESS...........................................................................................1
INTRODUCTION.......................................................................................1
THE TRUST..........................................................................................2
THE ROYALTY INTEREST...............................................................................6
THE UNITS.........................................................................................12
THE BP SUPPORT AGREEMENT..........................................................................14
THE PRUDHOE BAY UNIT..............................................................................14
INDEPENDENT OIL AND GAS CONSULTANTS' REPORT.......................................................20
INDUSTRY CONDITIONS AND REGULATIONS...............................................................25
CERTAIN TAX CONSIDERATIONS........................................................................25
ITEM 2. PROPERTIES........................................................................................27
ITEM 3. LEGAL PROCEEDINGS.................................................................................28
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS...................................................28
PART II
ITEM 5. MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS..............................................28
ITEM 6. SELECTED FINANCIAL DATA...........................................................................29
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................................................32
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE..............44
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................................................44
ITEM 11. EXECUTIVE COMPENSATION............................................................................44
ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT........................................44
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................................................44
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.................................44
SIGNATURES.................................................................................................46
INDEX TO EXHIBITS..........................................................................................47
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) 815-5092. The Company and
Standard Oil are indirect, wholly owned subsidiaries of BP Amoco p.l.c. ("BP").
Upon creation of the Trust, the Company conveyed to Standard Oil, and
Standard Oil, in turn, conveyed to the Trust an overriding royalty interest (the
"Royalty Interest"), which entitles the Trust to a royalty on 16.4246 percent of
the first 90,000 barrels of the average actual daily net production of oil and
condensate per quarter from the working interest of the Company as of February
28, 1989 in the Prudhoe Bay Unit located on the North Slope in Alaska (see "THE
PRUDHOE BAY UNIT" below). The Royalty Interest is free of any exploration and
development expenditures.
The only assets of the Trust are the Royalty Interest assigned to the
Trust and cash or cash equivalents held by the Trustee from time to time as
reserves or for distribution (the "Trust Estate"). The Trust is a passive
entity, and the Trustee has been given only such powers as are necessary for the
collection and distribution of revenues from the Royalty Interest and the
payment of Trust liabilities and expenses. The beneficial interest in the Trust
is divided into equal undivided units (the "Units"). The Units are not an
interest in or an obligation of the Company, Standard Oil or BP. The Delaware
Trust Act, under which the Trust was formed, entitles holders of the Units to
the same limitation of personal liability as stockholders of a Delaware
corporation.
The Company shares control of the operation of the Prudhoe Bay Unit
with other working interest owners. The operations of the Company and the other
working interest owners are governed by an agreement dated April 1, 1977 among
the State of Alaska and such working interest owners establishing the Prudhoe
Bay Unit (the "Prudhoe Bay Unit Agreement") and an agreement dated April 1, 1977
among the working interest owners governing Prudhoe Bay Unit operations (the
"Prudhoe Bay Unit Operating Agreement"). The Company has no obligation to
continue production from the Prudhoe Bay Unit or to maintain production at any
level and may interrupt or discontinue production at any time. The operation of
the Prudhoe Bay Unit is subject to normal operating hazards incident to the
production and transportation of oil in Alaska. In the event of damage to the
Prudhoe Bay Unit which is covered by insurance, the Company has no obligation to
use insurance proceeds to repair such damage and may elect to retain such
proceeds and close damaged areas to production.
The Trustee has no responsibility for the operation of the Prudhoe Bay
Unit or authority over the Company, Standard Oil or BP. The information in this
report relating to the Prudhoe Bay Unit, the calculation of the royalty payments
and certain other matters has been furnished to the Trustee by the Company.
1
THE TRUST
Duties and Limited Powers of Trustee
The duties of the Trustee are as specified in the Trust Agreement and
by the laws of the State of Delaware. The discussion of terms of the Trust
Agreement contained herein do not purport to be complete and are qualified in
their entirety by reference to the Trust Agreement itself, which is filed as an
exhibit to this report and is available upon request from the Trustee.
The basic function of the Trustee is to collect income from the Royalty
Interest, to pay from the Trust's income and assets all expenses, charges and
obligations of the Trust, and to pay available cash to holders of Units. The
Bank of New York (Delaware) has been appointed co-trustee in order to satisfy
certain requirements of the Delaware Trust Act, but The Bank of New York alone
is able to exercise the rights and powers granted to the Trustee in the Trust
Agreement.
The Trust Agreement grants the Trustee only such rights and powers as
are necessary to achieve the purposes of the Trust. The Trust Agreement
prohibits the Trust from engaging in any business, any commercial activity or,
with certain exceptions, investment activity of any kind and from using any
portion of the assets of the Trust to acquire any oil and gas lease, royalty or
other mineral interest.
The Trustee has the right to establish a cash reserve for the payment
of material liabilities of the Trust which may become due. Such reserve can only
be set up when the Trustee has determined that it is not practical to pay such
liabilities in a subsequent quarter out of funds anticipated to be available and
that, in the absence of such reserve, the Trust Estate is subject to the risk of
loss or diminution in value or the Trustee is subject to the risk of personal
liability for such liabilities. Furthermore, the Trustee must receive an
unqualified written opinion of counsel to the effect that such reserve will not
adversely affect the classification of the Trust as a "grantor trust" for
federal income tax purposes or cause the income from the Trust to be treated as
unrelated business taxable income for federal income tax purposes unless the
Trustee is unable to obtain such opinion and determines that the failure to
establish such reserve will be materially detrimental to the Unit Holders
considered as a whole or will subject the Trustee to the risk of personal
liability for such liabilities.
The Trustee has a limited power to borrow on behalf of the Trust on a
secured or unsecured basis. Such borrowing may be effected if at any time the
amount of cash on hand is not sufficient to pay liabilities of the Trust then
due. The Trustee can only borrow from an entity not affiliated with the Trustee.
Certain other conditions must also be satisfied, including, that the Trustee
must determine that it is not practical to pay such liabilities in a subsequent
quarter out of funds anticipated to be available and the Trust Estate is subject
to the risk of loss or diminution in value. The borrowing must be effected
pursuant to terms which (in the opinion of an investment banking firm or
commercial banking firm) are commercially reasonable when compared to other
available alternatives and the Trustee must receive an unqualified written
opinion of counsel to the effect that such borrowing will not adversely affect
the classification of the Trust as a "grantor trust" for federal income tax
purposes or cause the income from the Trust to be treated as unrelated business
taxable income for federal income tax purposes unless, the Trustee is unable to
obtain such opinion and determines that the failure to effect such borrowing
will be materially detrimental to the Unit Holders considered as a whole. To
secure payment of such indebtedness, the Trustee is authorized to mortgage,
pledge, grant security interests in or otherwise encumber the Trust Estate or
any portion thereof (including the Royalty Interest) and to carve out and convey
production payments. The borrowing itself and the pledges or other encumbrances
to secure borrowings are permitted without a vote of holders of Units. In the
event of such borrowings, no further Trust distributions may be made until the
indebtedness created by such borrowings has been paid in full.
2
The Trustee may sell Trust properties only as authorized by the
affirmative vote of the holders of Units representing 70 percent of the Units
outstanding, provided, however, that if such sale is effected in order to
provide for the payment of specific liabilities of the Trust then due and
involves a part, but not all or substantially all, of the Trust Estate, such
sale shall be approved by the affirmative vote of a majority of the holders of
the Units.
The Trustee may also sell for cash the Trust Estate, or a portion
thereof, if such sale is effected in order to provide for the payment of
specific liabilities of the Trust then due and cash on hand is insufficient and
the Trustee is unable to effect a borrowing by the Trust. The Trustee must also
determine that the failure to pay such liabilities at a later date will be
contrary to the best interest of the holders of Units and that it is not
practicable to submit the sale to a vote of the holders of Units. The sale must
be effected at a price which (in the opinion of an investment banking firm or
commercial banking firm) is at least equal to the fair market value of the
interest sold and is effected pursuant to commercially reasonable terms when
compared to other available alternatives. Again, the Trustee must receive an
unqualified written opinion of counsel to the effect that such sale will not
adversely affect the classification of the Trust as a "grantor trust" for
federal income tax purposes or cause the income from the Trust to be treated as
unrelated business taxable income for federal income tax purposes unless, the
Trustee is unable to obtain such opinion and determines that the failure to
effect such sale will be materially detrimental to the Unit Holders considered
as a whole. Finally, the Trustee may sell the Trust Estate upon termination of
the Trust.
Any sale of Trust properties must be for cash unless otherwise
authorized by the holders of Units, and the Trustee is obligated to distribute
the available net proceeds of any such sale to the holders of Units after
establishing reserves for liabilities of the Trust.
Except in certain circumstances, the Trustee is entitled to be
indemnified out of the assets of the Trust for any liability, expense, claim,
damage or other loss incurred by it in the performance of its duties unless such
loss results from its negligence, bad faith, or fraud or from its expenses in
carrying out such duties exceeding the compensation and reimbursement it is
entitled to under the Trust Agreement.
Employees
The Trust has no employees. All administrative functions of the Trust
are performed by the Trustee.
Property of the Trust
Except for cash and cash equivalents held by the Trustee from time to
time, the property of the Trust consists exclusively of the Royalty Interest.
The Royalty Interest was conveyed to the Trust pursuant to an Overriding Royalty
Conveyance dated February 27, 1989 between the Company and Standard Oil and a
Trust Conveyance dated February 28, 1989 between Standard Oil and the Trust. The
Overriding Royalty Conveyance and the Trust Conveyance are referred to
collectively herein as the "Conveyance." For a description of the terms of the
Royalty Interest, see "THE ROYALTY INTEREST" 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.
3
The Royalty Interest constitutes a non-operational interest in
minerals. The Trust has no right to take over operations or to share in any
operating decision whatsoever with respect to the Company's working interest in
the Prudhoe Bay Unit. The Company is not obligated to continue to operate any
well or maintain in force or attempt to maintain in force any portion of its
working interest in the Prudhoe Bay Unit when, in its reasonable and prudent
business judgment such well or interest ceases to produce or is not capable of
producing oil or gas in paying quantities.
Under the terms of the Prudhoe Bay Unit Operating Agreement, if the
Company fails to pay any costs and expenses chargeable to the Company under the
Prudhoe Bay Unit Operating Agreement and the production of oil and condensate is
insufficient to pay such costs and expenses, the Royalty Interest is chargeable
with a pro rata portion of such costs and expenses and is subject to the
enforcement against it of liens granted to the operators of the Prudhoe Bay
Unit. However, in the Conveyance the Company agreed to pay timely all costs and
expenses chargeable to it and to ensure that no such costs and expenses will be
chargeable against the Royalty Interest. The Trust is not liable for any
expense, claim, damage, loss or liability incurred by the Company or others
attributable to the Company's working interest in the Prudhoe Bay Unit or to the
oil produced from it, and the Company has agreed to indemnify the Trust and hold
it harmless against any such impositions.
The Company has the right to amend or terminate the Prudhoe Bay Unit
Agreement, the Prudhoe Bay Unit Operating Agreement and any leases or
conveyances with respect to its working interest in the exercise of its
reasonable and prudent business judgment without liability to the Trust. The
Company also has the right to sell or assign all or any part of its working
interest in the Prudhoe Bay Unit, so long as the sale or assignment is expressly
made subject to the Royalty Interest and the terms and provisions of the
Conveyance.
Amendment of the Trust Agreement
The Trust Agreement may be amended without a vote of the holders of
Units to cure an ambiguity, to correct or supplement any provision of the Trust
Agreement that may be inconsistent with any other such provision or to make any
other provision with respect to matters arising under the Trust Agreement that
do not adversely affect the holders of Units. The Trust Agreement may also be
amended with the approval of a majority of the outstanding Units at a meeting of
holders of Units. However, no such amendment may alter the relative rights of
Unit holders, unless approved by the affirmative vote of 100 percent of the
holders of Units and by the Trustee, or reduce or delay the distributions to the
holders of Units or effect certain other changes unless approved by the
affirmative vote of 80 percent of the holders of Units and by the Trustee. No
amendment will be effective until the Trustee has received a ruling from the
Internal Revenue Service or an opinion of counsel to the effect that such
modification will not adversely affect the classification of the Trust as a
"grantor trust" for federal income tax purposes or cause the income from the
Trust to be treated as unrelated business taxable income for federal income tax
purposes.
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.
4
Liabilities and Contingent Reserves
Because of the passive nature of the Trust's assets and the
restrictions on the power of the Trustee to incur obligations, the only
liabilities incurred by the Trust are routine administrative expenses, such as
Trustee's fees, and accounting, legal and other professional fees.
As discussed above, the Trustee may establish a cash reserve for the
payment of material liabilities of the Trust which may become due, if the
Trustee has determined that it is not practical to pay such liabilities out of
funds anticipated to be available for subsequent quarterly distributions and
that, in the absence of such a reserve, the trust estate is subject to the risk
of loss or diminution in value or The Bank of New York is subject to the risk of
personal liability for such liabilities. The Trustee is obligated to borrow
funds required to pay liabilities of the Trust when due, and to pledge or
otherwise encumber the Trust's assets, if it determines that the cash on hand is
insufficient to pay such liabilities and that it is not practical to pay such
liabilities out of funds anticipated to be available for subsequent quarterly
distributions. Borrowings must be repaid in full before any further
distributions are made to holders of Units. As previously described, certain
other necessary conditions must also be satisfied prior to the establishment of
a cash reserve or the Trust's borrowing of funds.
Termination of the Trust
The Trust is irrevocable and the Company has no power to terminate the
Trust. The Trust will terminate: (a) on or prior to December 31, 2010 upon a
vote of holders of not less than 70 percent of the outstanding Units, or (b)
after December 31, 2010 either (i) at such time as the net revenues from the
Royalty Interest for two successive years commencing after 2010 are less than
$1,000,000 per year, unless the net revenues during such period have been
materially and adversely affected by an event constituting force majeure, or
(ii) upon a vote of holders of not less than 60 percent of the outstanding
Units.
Upon termination of the Trust, the Company will have an option to
purchase the Royalty Interest (for cash unless holders representing 70 percent
of the Units outstanding (60 percent if the decision to terminate the Trust is
made after December 31, 2010) authorize the sale for non-cash consideration and
the Trustee has received a ruling from the Internal Revenue Service or an
opinion of counsel to the effect that such non-cash sale will not adversely
affect the classification of the Trust as a "grantor trust" for federal income
tax purposes or cause the income from the Trust to be treated as unrelated
business taxable income for federal income tax purposes) at a price equal to the
greater of (i) the fair market value of the trust estate as set forth in an
opinion of an investment banking firm, commercial banking firm or other entity
qualified to give an opinion as to the fair market value of the assets of the
Trust, or (ii) the 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.
5
If the Company does not exercise its option, the Trustee will sell the
Trust properties pursuant to procedures or material terms and conditions
approved by the vote of holders of 70 percent of the outstanding Units (60
percent if the sale is made after December 31, 2010), unless the Trustee
determines that it is not practicable to submit such procedures or terms to a
vote of the holders of Units, and the sale is effected at a price which is at
least equal to the fair market value of the trust estate as set forth in the
opinion mentioned above and pursuant to terms and conditions deemed commercially
reasonable by the investment banking firm, commercial banking firm or other
entity rendering such opinion.
After satisfying all existing liabilities and establishing adequate
reserves for the payment of contingent liabilities, the Trustee will distribute
all available proceeds to the holders of Units.
In the Trust Agreement, holders of Units have waived the right to seek
or secure any portion or distribution of the Royalty Interest or any other asset
of the Trust or any accounting during the term of the Trust or during any period
of liquidation and winding up.
Voting Rights of Holders of Units
Although holders of Units possess certain voting rights, their voting
rights are not comparable to those of shareholders of a corporation. For
example, there is no requirement for annual meetings of holders of Units or
annual or other periodic reelection of the Trustee.
A meeting of the holders of Units may be called at any time to act with
respect to any matter which the holders of Units are authorized to act pursuant
to the Trust Agreement. Any such meeting may be called by the Trustee in its
discretion and will be called (i) as soon as practicable after receipt of a
written request by the Company or (ii) as soon as practicable after receipt of a
written request that sets forth in reasonable detail the action proposed to be
taken at such meeting and is signed by holders of Units owning not less than 25
percent of the then outstanding Units or (iii) as may be required by applicable
laws or regulations of the New York Stock Exchange. All such meetings are
required to take place in the Borough of Manhattan, The City of New York.
THE ROYALTY INTEREST
The Royalty Interest is a property right under Alaska law which burdens
production, but there is no other security interest in the reserves or
production revenues to which the Royalty Interest is entitled. The royalty
payable to the Trust under the Royalty Interest for each calendar quarter is the
sum of the product of (i) the Royalty Production and (ii) the Per Barrel Royalty
for each day in the quarter. The payment under the Royalty Interest for any
calendar quarter may not be less than zero nor more than the aggregate value of
the total production of oil and condensate from the Company's working interest
in the Prudhoe Bay Unit for such calendar quarter, net of the State of Alaska
royalty and less the value of any applicable payments made to affiliates of the
Company.
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.
6
Per Barrel Royalty
The "Per Barrel Royalty" in effect for any day is an amount equal to
the WTI Price for such day less the sum of (i) the product of the Chargeable
Costs multiplied by the Cost Adjustment Factor and (ii) Production Taxes.
WTI Price
The "WTI Price" for any trading day means (i) the latest price
(expressed in dollars per barrel) for West Texas intermediate crude oil of
standard quality having a specific gravity of 40 degrees API for delivery at
Cushing, Oklahoma ("West Texas Crude"), quoted for such trading day by the Dow
Jones International Petroleum Report (which is published in The Wall Street
Journal) or if the Dow Jones International Petroleum Report does not publish
such quotes, then such price as quoted by Reuters, or if Reuters does not
publish such quotes, then such price as quoted in Platt's Oilgram Price Report,
or (ii) if for any reason such publications do not publish the price of West
Texas Crude, then the WTI Price will mean, until the price quotations described
in (i) are again available, the simple average of the daily mean prices
(expressed in dollars per barrel) quoted for West Texas Crude by one major oil
company, one petroleum broker and one petroleum trading company, in each case
unaffiliated with BP and having substantial U.S. operations. Such major oil
company, petroleum broker and petroleum trading company will be designated by
the Company from time to time. In the event that prices for West Texas Crude are
not quoted so as to permit the calculation of the WTI Price, "West Texas Crude,"
for the purposes of calculating the WTI Price will mean such other light sweet
domestic crude oil of standard quality as is designated by the Company and
approved by the Trustee in the exercise of its reasonable judgment, with
appropriate allowance for transportation costs to the Gulf Coast (or other
appropriate location) to equilibrate such price to the WTI Price. The WTI Price
for any day which is not a trading day is the WTI Price for the preceding
trading day.
7
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, 2000 were: $8.50
during 1996; $8.85 during 1997; $9.30 during 1998; $9.80 during 1999; and $10.00
during 2000. Chargeable Costs for the calendar year ending December 31, 2001 and
subsequent years are shown in the following table:
For the For the
Year Ending Chargeable Costs Year Ending Chargeable Costs
December 31 Per Barrel December 31 Per Barrel
----------- ---------------- ----------- ----------------
2001 10.75 2011 16.60
2002 11.25 2012 16.70
2003 11.75 2013 16.80
2004 12.00 2014 16.90
2005 12.25 2015 17.00
2006 12.50 2016 17.10
2007 12.75 2017 17.20
2008 13.00 2018 20.00
2009 13.25 2019 23.75
2010 14.50 2020 26.50
After 2020, Chargeable Costs increase at a uniform rate of $2.75 per
year.
Chargeable Costs may be reduced in future years by up to $1.20 per
barrel in the following circumstances:
(1) Chargeable Costs will be reduced by up to $1.20 per barrel in 2006
and subsequent years if, between January 1, 2001 and December 31, 2005, either
(a) an additional 400,000,000 STB of proved reserves (before taking into account
any production therefrom) have not been added to proved reserves allocated to
the Subject Leases (including, for the purpose of this calculation, a credit
equal to the number of STB of proved reserves in excess of 300,000,000 added to
the Company's reserves after December 31, 1987 and before January 1, 2001), or
(b) an additional 100,000,000 STB of proved reserves (before taking into account
any production therefrom) have not been added to the reserves allocated to the
Subject Leases, without allowing any credit for additions prior to January 1,
2001. In general, "proved reserves" for purposes of this determination consist
of the Company's estimate (determined to be reasonable by independent petroleum
engineers) of the quantities of crude oil and condensate that geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years under existing economic and operating conditions from the Prudhoe
Bay (Permo-Triassic Reservoir) in the Prudhoe Bay Unit. See "THE PRUDHOE BAY
UNIT - Reserve Estimates" below.
8
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 56.1 793.3
The Company anticipates that additional drilling, workovers, facilities
modifications, new recovery projects, and programs for production enhancement
and optimization are expected to mitigate, but not eliminate the recent decline
in gross oil and condensate production capacity. As of December 31, 2000, the
cumulative additions to proved reserves allocated to the Subject Leases were
sufficient to prevent any reduction in Chargeable Costs during the years 2001
through 2005. However, significant downward revisions of proved reserve
estimates in 2001 or subsequent years could result in a reduction of Chargeable
Costs being required as described above in the year 2006 or thereafter.
Cost Adjustment Factor
The "Cost Adjustment Factor" is the ratio of (1) the Consumer Price
Index published for the most recently past February, May, August or November, as
the case may be, to (2) 121.1 (the Consumer Price Index for January 1989),
except that (a) if for any calendar quarter the average WTI Price is $18.00 or
less, then the Cost Adjustment Factor for that quarter will be the Cost
Adjustment Factor for the immediately preceding quarter, and (b) the Cost
Adjustment Factor for any calendar quarter in which the average WTI Price
exceeds $18.00, after a calendar quarter during which the average WTI Price is
equal to or less than $ 18.00, and for each following calendar quarter in which
the average WTI Price is greater than $18.00, will be the product of (x) the
Cost Adjustment Factor for the most recently past calendar quarter in which the
average WTI Price is equal to or less than $18.00 and (y) a fraction, the
numerator of which will be the Consumer Price Index published for the most
recently past February, May, August or November, as the case may be, and the
denominator of which will be the Consumer Price Index published for the most
recently past February, May, August or November during a quarter in which the
average WTI Price is equal to or less than $18.00. The "Consumer Price Index" is
the U.S. Consumer Price Index, all items and all urban consumers, U.S. city
average, 1982-84 equals 100, as first published, without seasonal adjustment, by
the Bureau of Labor Statistics, Department of Labor, without regard to
subsequent revisions or corrections.
9
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. The Alaska Oil and Gas Conservation Tax was repealed on July 1,
1999.
10
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 Chargeable Adjustment Chargeable Production Per Barrel
WTI Price Costs Factor Costs Taxes Royalty
--------- ---------- ---------- ---------- ---------- ----------
1996:
1st Qtr 19.74 8.50 1.227 10.43 2.17 7.14
2nd Qtr 21.70 8.50 1.241 10.55 2.45 8.70
3rd Qtr 22.36 8.50 1.247 10.59 2.55 9.22
4th Qtr 24.71 8.50 1.257 10.68 2.89 11.13
1997:
1st Qtr 22.86 8.85 1.265 11.19 2.61 9.06
2nd Qtr 19.91 8.85 1.269 11.23 2.16 6.52
3rd Qtr 19.75 8.85 1.274 11.28 2.14 6.34
4th Qtr 19.94 8.85 1.280 11.33 2.16 6.45
1998:
1st Qtr 15.96 9.30 1.280 11.90 1.56 2.49
2nd Qtr 14.58 9.30 1.280 11.90 1.36 1.32
3rd Qtr 14.15 9.30 1.280 11.90 1.29 0.96
4th Qtr 12.80 9.30 1.280 11.90 1.10 0.00
1999:
1st Qtr 13.08 9.80 1.280 12.54 1.13 0.00
2nd Qtr 17.44 9.80 1.280 12.54 1.79 3.11
3rd Qtr 21.71 9.80 1.287 12.61 2.42 6.68
4th Qtr 24.60 9.80 1.296 12.70 2.84 9.05
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
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.
11
THE UNITS
Units
Each Unit represents an equal undivided share of beneficial interest in
the Trust. The Units do not represent an interest in or an obligation of the
Company, Standard Oil or any of their respective affiliates. Units are evidenced
by transferable certificates issued by the Trustee. Each Unit entitles its
holder to the same rights as the holder of any other Unit. The Trust has no
other authorized or outstanding class of equity securities.
Distributions of Income
The Company makes quarterly payments to the Trust of the amounts due
with respect to the Trust's Royalty Interest on the fifteenth day following the
end of each calendar quarter or, if the fifteenth is not a business day, on the
next succeeding business day (the "Quarterly Record Date"). The Trustee, to the
extent possible, pays all expenses of the Trust for each quarter on the
Quarterly Record Date. The Trustee then distributes an amount equal to the
excess, if any, of the cash received by the Trust from the Royalty Interests
over the expenses and payments of liabilities of the Trust, subject to
adjustments for changes made by the Trustee in any cash reserve established for
the payments of estimated liabilities of the Trust (the "Quarterly
Distribution") to the persons in whose names the Units were registered at the
close of business on the immediately preceding Quarterly Record Date.
The Trust Agreement provides that the Trustee shall pay the Quarterly
Distribution on the fifth day after the Trustee's receipt of the amount paid by
the Company on the Quarterly Record Date, and that collected cash balances being
held by the Trustee for distribution shall be invested in obligations issued or
unconditionally guaranteed by the United States or any agency or instrumentality
thereof and secured by the full faith and credit of the United States
("Government Obligations") or, if Government Obligations with a maturity date on
the date of the distribution to Unit holders are not available, in repurchase
agreements with banks having capital, surplus and undivided profits of
$100,000,000 or more (which may include The Bank of New York) secured by
Government Obligations. If time does not permit the Trustee to invest collected
funds in investments of the type described in the preceding sentence, the
Trustee may invest such funds overnight in a time deposit with a bank meeting
the foregoing requirement (including The Bank of New York).
Reports to Unit Holders
Within 90 days after the end of each calendar year, the Trustee mails
to the holders of record of Units at any time during the calendar year a report
containing information to enable them to make the calculations necessary for
federal and Alaska income tax purposes, including the calculation of any
depletion or other deduction which may be available to them for the calendar
year. In addition, after the end of each calendar year the Trustee mails to
holders of Units an annual report containing audited financial statements of the
Trust, a letter of the independent petroleum engineers engaged by the Trust
setting forth a summary of such firm's determinations regarding the Company's
estimates of proved reserves and other related matters, and certain other
information required by the Trust Agreement.
12
Following the end of each quarter, the Trustee mails Unit holders a
quarterly report showing the assets and liabilities, receipts and disbursements
and income and expenses of the Trust and the Royalty Production for such
quarter.
Limited Liability of Unit Holders
The Trust Agreement provides that the holders of Units are, to the full
extent permitted by Delaware law, entitled to the same limitation of personal
liability extended to stockholders of private corporations for profit under
Delaware law.
Possible Divestiture of Units
The Trust Agreement imposes no restrictions on nationality or other
status of the persons eligible to hold Units. However, the Trust Agreement
provides that if at any time the Trust or the Trustee is named a party in any
judicial or administrative proceeding seeking the cancellation or forfeiture of
any property in which the Trust has an interest because of the nationality, or
any other status, of any one or more holders, the following procedures will be
applicable:
(i) The Trustee will give written notice of the existence
of such proceedings to each holder whose nationality or other status is
an issue in the proceeding. The notice will contain a reasonable
summary of such proceeding and will constitute a demand to each such
holder that he dispose of his Units within 30 days to a party not of
the nationality or other status at issue in the proceeding described in
the notice.
(ii) If any holder fails to dispose of his Units in
accordance with such notice, the Trustee will redeem, at any time
during the 90-day period following the termination of the 30-day period
specified in the notice, any Unit not so transferred for a cash price
per Unit equal to the closing price of the Units on the stock exchange
on which the Units are then listed or, in the absence of any such
listing, the closing bid price on the NASDAQ National Market System if
the Units are so quoted or, if not, the mean between the closing bid
and asked prices for the Units in the over-the-counter market, in
either case as of the last business day prior to the expiration of the
30-day period stated in the notice. If the Units are neither listed nor
traded in the over-the-counter market, the price will be the fair
market value of the Units as determined by a recognized firm of
investment bankers or other competent advisor or expert.
Units redeemed by the Trustee will be cancelled. The Trustee may, in
its sole discretion, cause the Trust to borrow any amount required to redeem the
Units. If the purchase of Units from an ineligible holder by the Trustee would
result in a non-exempt "prohibited transaction" under ERISA, or under the
Internal Revenue Code of 1986, the Units subject to the Trustee's right of
redemption will be purchased by the Company or a designee thereof, at the above
described purchase price.
Issuance of Additional Units
The Trust Agreement provides that the Company or an affiliate from time
to time may assign to the Trust additional royalty interests meeting certain
conditions, and, upon satisfaction of various other conditions, including
receipt by the Trustee of a ruling from the Internal Revenue Service to the
effect that neither the existence nor the exercise of the right to assign the
additional royalty interest or the power to accept such assignment will
adversely affect the classification of the Trust as a "grantor trust" for
federal income tax purposes, the Trust may issue up to an additional 18,600,000
Units. The 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 Ratings Group
of at least A- or an equivalent rating from at least one nationally-recognized
statistical rating organization (after giving effect to the sale or transfer to
such entity of all or substantially all of the Company's working interest in the
Prudhoe Bay Unit and the assumption by such entity of all of the Company's
obligations under the Conveyance and of all BP's obligations under the Support
Agreement).
THE PRUDHOE BAY UNIT
General
The Prudhoe Bay field (the "Field") is located on the North Slope of
Alaska, 250 miles north of the Arctic Circle and 650 miles north of Anchorage.
The Field extends approximately 12 miles by 27 miles and contains nearly 150,000
productive acres. The Field, which was discovered in 1968 by BP and others, has
been in production since 1977. The Field is the largest producing oil field in
North America. As of December 31, 2000, approximately 10.1 billion STB of oil
and condensate had been produced from the Field. Field development is well
advanced with approximately $18.0 billion gross capital spent and a total of
about 2,095 wells drilled. Other large fields located in the same area include
the Kuparuk, Endicott, and Lisburne fields. Production from those fields is not
included in the Royalty Interest.
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 ("Arco") were the two Field operators. On July 1,
2000, the Company assumed sole-operatorship of the field. Other Field owners
include affiliates of Exxon Mobil Corporation ("Exxon Mobil"), Phillips
Petroleum Company ("Phillips") and Chevron Corporation ("Chevron").
Geology
The principal hydrocarbon accumulations at Prudhoe Bay are in the
Ivishak sandstone of the Sadlerochit Group at a depth of approximately 8,700
feet below sea level. The Ivishak is overlain by four minor reservoirs of
varying extent which are designated the Put River, Eileen, Sag River and Shublik
(collectively, "PESS") formations. Underlying the Sadlerochit Group are the
oil-bearing Lisburne and Endicott formations. The net production referred to
herein pertains only to the Ivishak and PESS formations, collectively known as
the Prudhoe Bay (Permo-Triassic) Reservoir, and does not pertain to the Lisburne
and Endicott formations.
The Ivishak sandstone was deposited, commencing some 250 million years
ago, during the Permian and Triassic geologic periods. The sediments in the
Ivishak are composed of sandstone, conglomerate and shale which were deposited
by a massive braided river and delta system that flowed from an ancient mountain
system to the north. Oil was trapped in the Ivishak by a combination of
structural and stratigraphic trapping mechanisms.
Gross reservoir thickness is 550 feet, with a maximum oil column
thickness of 425 feet. The original oil column is bounded on the top by a
gas-oil contact, originally at 8,575 feet below sea level across the main field,
and on the bottom by an oil-water contact at approximately 9,000 feet below sea
level. A layer of heavy oil and tar overlays the oil-water contact in the main
field and has an average thickness of around 40 feet.
Oil Characteristics
The produced oil from the reservoir is a medium grade, low sulfur crude
with an average specific gravity of 27 degrees API. The gas cap composition is
such that, upon surfacing, a liquid hydrocarbon phase, known as condensate, is
formed.
The interests of the Unit holders are based upon oil produced from the
oil rim and condensate produced from the gas cap, but not upon gas production
(which is currently uneconomic) or natural gas liquids production stripped from
gas produced.
Prudhoe Bay Unit Operation and Ownership
Since several companies hold acreage within the Field's limits, a unit
was established to ensure optimum development of the Field. The Prudhoe Bay
Unit, which became effective on April 1, 1977, divided the Field into two
operating areas. 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 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.
15
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, 2000 is summarized in the following table:
Oil Rim Gas Cap
------- -------
BP....................................... 26.34% (a) 26.54%
Exxon Mobil.............................. 36.37 36.64
Phillips................................. 36.05 36.32
Others................................... 1.24 0.50
Total............................... 100.00% 100.00%
====== ======
----------
(a) The Trust's share of oil production is computed based on BP's ownership
interest of 50.68 percent as of February 28, 1989. Effective December 31,
1995, the Company acquired the interest of Amerada Hess Corporation of
0.5379191 percent on the oil rim participating area. Under the terms of the
Conveyance, this increase in the Company's participation is not allocated
to the Subject Leases and does not increase the Trust's Royalty Interest.
Effective January 1, 2000, the Company and certain other Prudhoe Bay
working interest owners cross-assigned interests in the Prudhoe Bay Field
pursuant to the Prudhoe Bay Unit Alignment Agreement ("the Alignment
Agreement"). Under the terms of the Alignment Agreement, the Company
retained all rights, obligations and liabilities associated with the Trust
and this decrease in the Company's participation is not allocated to the
Subject Leases and does not decrease the Trust's Royalty Interest.
(b) The Trust's share of condensate production is computed based on BP's
ownership interest of 13.84 percent as of February 28, 1989. Effective
January 1, 2000, the Company and certain other Prudhoe Bay working interest
owners cross-assigned interests in the Prudhoe Bay Field pursuant to the
Alignment Agreement. Under the terms of the Alignment Agreement, the
Company retained all rights, obligations and liabilities associated with
the Trust and this increase in the Company's participation is not allocated
to the Subject Leases and does not increase the Trust's Royalty Interest.
Historical Production
Production began on June 19, 1977, with the completion of the Trans
Alaska Pipeline System. The pipeline has a capacity of approximately 1.4 million
STB of oil per day.
As of December 31, 2000 there were about 828 active producing oil
wells, 36 gas reinjection wells, 75 water injection wells and 104 water and
miscible gas injection wells in the Field. In terms of individual well
performance, oil production rates range from 100 to 5,500 STB of oil per day.
Currently, the average well production rate is about 620 STB of oil per day.
16
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:
Oil Condensate
Year ---------------------- ------------------------
Ended Total Subject Total Subject
December 31 Field Leases Field Leases
----------- ----- ------ ----- ------
(Thousand STB per day)
1996 583.1 258.6 187.6 22.7
1997 512.8 227.4 177.1 21.4
1998 442.3 196.1 165.2 20.0
1999 380.9 170.7 151.5 18.3
2000 364.0 161.4 146.7 17.8
The Company estimates that production will decline at an average rate
of approximately 10 percent per year for the next one to three years, and that
the rate of decline will decrease to approximately five percent per year by the
year 2030.
Transportation of Prudhoe Bay Oil
Production from the Field is carried to Pump Station 1, which is the
starting point for the Trans Alaska Pipeline System, through two 34-inch
diameter transit lines, one from each half of the Field. At Pump Station 1,
Alyeska Pipeline Service Company, the pipeline operator, meters the oil and
pumps it south to Valdez where it is either loaded onto marine tankers or stored
temporarily. It takes the oil about 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 999.6 million STB as of December 31, 2000.
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 2011. 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.
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, 2000 were 90.7 million barrels of oil and condensate, of
which 84.3 million barrels were proved developed reserves and 6.4 million
barrels were proved undeveloped reserves. Using procedures specified in
Financial Accounting Standards Board Statement of Financial Standards No. 69,
the Company calculated that as of December 31, 2000 production of oil and
condensate from the proved reserves allocated to the Trust will result in
estimated future net revenues to the Trust of $521 million, with a present value
of $306 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.
18
The following table shows the net remaining proved reserves of oil and
condensate allocated to the Subject Leases, the net proved reserves allocated to
the Trust, and the WTI Prices on the dates indicated:
Net Proved Reserves
------------------- WTI Prices
December 31 Subject Leases (a) Trust (b) Per Barrel
----------- ------------------ --------- ----------
(Million STB)
1996 1,247.0 111.1 25.93
1997 1,154.7 64.8 17.78
1998 1,075.4 0.0 12.05
1999 1,007.6 93.6 25.60
2000 999.6 90.7 26.83
----------
(a) Includes proved undeveloped reserves of 223.4 million STB at December 31,
1996; 190.2 million STB at December 31, 1997; 109.8 million STB at December
31, 1998; 108 million STB at December 31, 1999; and 137.3 million STB at
December 31, 2000.
(b) Includes proved undeveloped reserves of 9.1 million STB at December 31,
1996; 1.3 million STB at December 31, 1997; 0.0 STB at December 31, 1998;
4.5 million STB at December 31, 1999; and 6.4 million STB at December 31,
2000.
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
[LETTERHEAD OF MILLER AND LENTS, LTD.]
February 28, 2001
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street 21 W
New York, New York 10286
Re: Estimates of Proved Reserves,
Future Production Rates, and
Future Net Revenues for the
BP Prudhoe Bay Royalty Trust
As of December 31, 2000
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, 2000. 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 20, 2001 addressed to Mr. Patrick O'Leary 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
MILLER AND LENTS, LTD.
The Bank of New York February 28, 2001
Trustee, BP Prudhoe Bay Royalty Trust
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, 2000, of
90.7 million barrels of oil and condensate are, in the
aggregate, reasonable. Of the 90.7 million barrels of total
Proved Reserves, 84.3 million barrels are Proved Developed
Reserves, and 6.4 million barrels are Proved Undeveloped
Reserves.
5. Utilizing the specified procedures outlined in Financial
Accounting Standards Board Statement of Financial Accounting
Standards No. 69, BP Exploration (Alaska) Inc. calculated that
as of December 31, 2000, production of the Proved Reserves
will result in Estimated Future Net Revenues of $521 million
and Present Value of Estimated Future Net Revenues of $306
million to the BP Prudhoe Bay Royalty Trust. These estimates
are reasonable.
21
MILLER AND LENTS, LTD.
The Bank of New York February 28, 2001
Trustee, BP Prudhoe Bay Royalty Trust
6. BP Exploration (Alaska) Inc. estimated that, as of December
31, 2000, 793.3 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 2011 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 $26.83 per
barrel on December 31, 2000, current Production Taxes, and the
Chargeable Costs adjusted as prescribed by the Overriding
Royalty Conveyance, the projection that royalty payments will
continue through the year 2017 is reasonable. BP Exploration
(Alaska) Inc. expects continued economic production at a
declining rate through the year 2030; however, for the
economic conditions and production forecast as of December 31,
2000, the Per Barrel Royalty will be zero following the year
2017. Therefore, no reserves are currently attributed to the
BP Prudhoe Bay Royalty Trust after that date.
9. Even if expected reservoir performance does not change, the
estimated reserves, economic life, and future revenues
attributable to the BP Prudhoe Bay Royalty Trust may change
significantly in the future. This may result from changes in
the West Texas Intermediate Price or from changes in other
prescribed variables utilized in calculations defined by the
Overriding Royalty Conveyance.
Estimates of ultimate and remaining reserves and production scheduling
depend upon assumptions regarding expansion or implementation of alternative
projects or development programs and upon strategies for production
optimization. BP Exploration (Alaska) Inc. has continual reservoir management,
surveillance, and planning efforts dedicated to (1) gathering new information,
(2) improving the accuracy of its reserves and production capacity estimates,
(3) recognizing and exploiting new opportunities, (4) anticipating potential
problems and taking corrective actions, and (5) identifying, selecting, and
implementing optimum recovery program and cost reduction alternatives. Given
this significant effort and ever-changing economic conditions, estimates of
reserves and production profiles will change periodically.
22
MILLER AND LENTS, LTD.
The Bank of New York February 28, 2001
Trustee, BP Prudhoe Bay Royalty Trust
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
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.
23
MILLER AND LENTS, LTD.
The Bank of New York February 28, 2001
Trustee, BP Prudhoe Bay Royalty Trust
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 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.
26
Section 897 of the Internal Revenue Code and the Treasury Regulations
thereunder treat the Trust as if it were a United States real property holding
corporation. Foreign holders owning more than five percent of the outstanding
Units are subject to United States federal income tax on the gain on the
disposition of their Units. Foreign Unit holders owning less than five percent
of the outstanding Units are not subject to United States federal income tax on
the gain on the disposition of their Units, unless they have elected under
Internal Revenue Code section 871 or section 872 to treat the income from the
Royalty Interest as effectively connected with the conduct of a United States
trade or business.
If a Foreign person is a corporation which made an election under
Internal Revenue Code section 882(d), the corporation would also be subject to a
30 percent tax under Internal Revenue Code section 884. This tax is imposed on
U.S. branch profits of a foreign corporation that are not reinvested in the U.S.
trade or business. This tax is in addition to the tax on effectively connected
income. The branch profits tax may be either reduced or eliminated by treaty.
Sale of Units
Generally, a Unit holder will realize gain or loss on the sale or
exchange of his Units measured by the difference between the amount realized on
the sale or exchange and his adjusted basis for such Units. Gain on the sale of
Units by a holder that is not a dealer with respect to such Units will generally
be treated as capital gain. However, pursuant to Internal Revenue Code section
1254, certain depletion deductions claimed with respect to the Units must be
recaptured as ordinary income upon sale or disposition of such interest.
Backup Withholding
A payor must withhold 31 percent of any reportable payment if the payee
fails to furnish his taxpayer identification number ("TIN") to the payor in the
required manner or if the Secretary of the Treasury notifies the payor that the
TIN furnished by the payee is incorrect. Unit holders will avoid backup
withholding by furnishing their correct TINs to the Trustee in the form required
by law.
State Income Taxes
Unit holders may be required to report their share of income from the
Trust to their state of residence or commercial domicile. However, only
corporate Unit holders will need to report their share of income to the State of
Alaska. Alaska does not impose an income tax on individuals or estates and
trusts. All Trust income is Alaska source income to corporate Unit holders and
should be reported accordingly.
ITEM 2. PROPERTIES
Reference is made to Item 1 for the information required by this item.
ITEM 3. LEGAL PROCEEDINGS
None.
27
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS
None.
PART II
ITEM 5. MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS
The Units are listed and traded on the New York Stock Exchange under
the symbol BPT. The following table shows the high and low sales prices per Unit
on the New York Stock Exchange and the cash distributions paid per Unit, for
each calendar quarter in the two years ended December 31, 1999 and 2000.
Distributions
High Low Per Unit
---- --- -------------
1999:
First Quarter $ 8 15/16 $ 4 7/16 $0.000(a)
Second Quarter 8 9/16 5 7/16 0.000(a)
Third Quarter 11 7 5/16 0.166
Fourth Quarter 10 15/16 8 1/16 0.404
2000:
First Quarter $10 1/2 8 5/8 $0.546
Second Quarter 11 15/16 8 7/8 0.763
Third Quarter 14 9/16 10 5/8 0.757
Fourth Quarter 14 15/16 11 9/16 0.917
As of December 31, 2000, 21,400,000 Units were outstanding and were
held by approximately 926 holders of record.
(a) Due to the decline in WTI Prices, the Trust did not receive
distributions during the first and second quarters of 1999.
Future payments of cash distributions are dependent on such factors as
the prevailing WTI Price, the relationship of the rate of change in the WTI
Price to the rate of change in the Consumer Price Index, the Chargeable Costs,
the rates of Production Taxes prevailing from time to time, and the actual
production from the Prudhoe Bay Unit. See "THE ROYALTY INTEREST" in Item 1.
28
ITEM 6. SELECTED FINANCIAL DATA
The following table presents in summary form selected financial
information regarding the Trust.
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(In thousands, except per Unit amounts)
Royalty revenues $ 65,026 13,443 15,163 44,582 42,263
Interest income 92 60 17 21 0
Trust administration expenses 732 798 614 845 750
Expenses reserve 500 500 0 0 0
----------- ---------- ---------- ---------- ----------
Cash earnings $ 63,886 12,205 14,566 43,758 41,513
Cash distributions $ 63,838 12,205 14,566 43,758 41,513
Cash distributions per unit $ 2.983 0.570 0.681 2.045 1.940
Units outstanding 21,400,000 21,400,000 21,400,000 21,400,000 21,400,000
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.
29
Upon the resumption of distributions in the third quarter of 1999,
attributable to the increase in the WTI Price in the second quarter of 1999, the
Trustee established a cash reserve to provide liquidity to the Trust during any
future periods in which the Trust does not receive a distribution. The Trustee
set aside $1,000,000 in the cash reserve account, out of quarterly distributions
received by the Trust. This amount was set aside over the course of four
quarters, with one quarter of such amount being set aside each quarter with
$250,000 from the July 15, 1999 distribution, $250,000 from the October 15, 1999
distribution, additional $250,000 from the January 15, 2000 distribution and
$250,000 from the April 15, 2001 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. The Trustee has determined to distribute any interest received
from the investment to the holders of Units upon maturity on that next Quarterly
Record Date. The Trustee anticipates that it will keep this cash reserve program
in place until termination of the Trust.
As discussed under "BUSINESS - Certain Tax Considerations", amounts
received by the Trust as quarterly distributions are income to the holders of
the Units, (as will be any earning on investment of the cash reserve) and must
be reported by the holders of the Units, even if such amounts are used to repay
borrowings or establish a cash reserve and are not received by the holders of
the Units.
Results of Operations
Relatively modest changes in oil prices will significantly affect the
Trust's revenues and results of operations. Crude oil prices are subject to
significant changes in response to fluctuations in the domestic and world supply
and demand and other market conditions as well as the world political situation
as it affects OPEC and other producing countries. The effect of changing
economic conditions on the demand and supply for energy throughout the world and
future prices of oil cannot be accurately projected.
Royalty revenues are generally received on the Quarterly Record Date
(generally the fifteenth day of the month) following the end of the calendar
quarter in which the related Royalty Production occurred. The Trustee, to the
extent possible, pays all expenses of the Trust for each quarter on the
Quarterly Record Date on which the revenues for the quarter are received. For
the statement of cash earnings and distributions, revenues and Trust expenses
are recorded on a cash basis and, as a result, distributions to Unit holders in
the years ended December 31, 2000, 1999 and1998 are attributable to the
Company's operations during the twelve-month periods ended September 30, 2000,
1999 and1998, respectively.
As long as the Company's average daily net production from the Prudhoe
Bay Unit exceeds 90,000 barrels, which the Company currently projects will
continue until the year 2011, 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.
30
As a result of the increase in the WTI Price during the year 2000
royalty revenues to the Trust and cash distributions to the holders of Units
increased in 2000. For the fiscal year of 2000 up to the time of this report the
WTI Price has been above the level necessary for the Trust to receive a Per
Barrel Royalty. Whether the Trust will be entitled to future distributions
during fiscal year 2001 depends on WTI Prices prevailing during the
remainder of the year.
2000 compared to 1999
Royalty revenues and cash distributions in 2000 increased by
approximately 383.7% and 423.0%, respectively, from 1999, as a result of the
increased average WTI Prices throughout 2000 (see "THE ROYALTY INTEREST-Per
Barrel Royalty Calculations" in Item 1). Trust administration expenses decreased
by 8.3% from 1999 to 2000 due largely to the increased expense incurred by the
Trust in setting up the cash reserve in 1999. As a percentage of cash earnings
the Trust administration expense decreased to 1.1% from 6.5% in 1999.
1999 compared to 1998
Royalty revenues and cash distributions in 1999 decreased by
approximately 11.3% and 16.2%, respectively, from 1998, as a result of the
decline in world oil prices during 1998 and early 1999 (see "THE ROYALTY
INTEREST-Per Barrel Royalty Calculations" in Item 1). Due to an increase in oil
prices starting from the second quarter, the Trust earned all of its royalty
revenue for the 1999 fiscal year in the third and fourth quarters of 1999. Cash
distributions paid to holders of Units decreased at a greater rate, 16.2%, than
royalty revenues, 11.3%, due to the $500,000 contributed to the cash reserve
during the second-half of 1999 and the increase in the payment of Trust
administration fees and expenses. Trust administration expenses increased 30%
from 1998 to 1999 and as a percentage of cash earnings increased to 6.5% from
4.2% in 1998. The increased dollar amount in the Trustee's expenses was due
largely to the fees and expenses necessary to establish the cash reserve which
in conjunction with the decrease in cash earnings contributed to the increase of
Trustee expenses as a percentage of cash earnings.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.
Not applicable.
31
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, 2000 and 1999............34
Statement of Cash Earnings and Distributions for the years ended
December 31, 2000, 1999 and 1998...............................................................35
Statements of Changes in Trust Corpus for the years ended
December 31 2000, 1999 and 1998................................................................36
Notes to Financial Statements..................................................................37
32
BP PRUDHOE BAY ROYALTY TRUST
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, 2000 and 1999,
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,
2000. 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, 2000 and 1999, 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, 2000, on the basis of accounting described
in note 2.
KPMG LLP
New York, New York
March 30, 2001
33
BP PRUDHOE BAY ROYALTY TRUST
Statements of Assets, Liabilities and Trust Corpus
[Prepared on a modified basis of cash receipts and disbursements]
December 31, 2000 and 1999
(In thousands, except unit data)
2000 1999
------- -------
Assets
Royalty Interest, net (notes 1, 2 and 3) $20,085 22,596
Cash equivalents 1,048 500
------- -------
Total assets $21,133 23,096
======= =======
Liabilities and Trust Corpus
Accrued expenses $ 464 470
Trust Corpus (40,000,000 units of beneficial
interest authorized, 21,400,000 units issued
and outstanding) 20,669 22,626
------- -------
Total liabilities and Trust Corpus $21,133 23,096
======= =======
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]
For the Years Ended December 31, 2000, 1999 and 1998
(In thousands, except unit data)
2000 1999 1998
------------ ------------ ------------
Royalty revenues $ 65,026 13,443 15,163
Interest Income 92 60 17
Less: Trust administrative expenses (732) (798) (614)
Expense reserve (500) (500) --
------------ ------------ ------------
Cash earnings $ 63,886 12,205 14,566
============ ============ ============
Cash distributions $ 63,838 12,205 14,566
============ ============ ============
Cash distributions per unit $ 2.983 0.570 0.681
============ ============ ============
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]
For the Years Ended December 31, 2000, 1999 and 1998
(In thousands)
2000 1999 1998
-------- -------- --------
Trust Corpus at beginning of year $ 22,626 25,008 242,829
Cash earnings 63,886 12,205 14,566
Increase in cash reserve 500 487 13
Decrease (increase) in accrued expenses 6 (367) 92
Cash distributions (63,838) (12,205) (14,566)
Amortization of Royalty Interest (2,511) (2,502) (44,408)
Impairment write-down (Note 3) -- -- (173,518)
-------- -------- --------
Trust Corpus at end of year $ 20,669 22,626 25,008
======== ======== ========
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, 2000, 1999 and 1998
(1) Formation of the Trust and Organization
BP Prudhoe Bay Royalty Trust (the "Trust"), a grantor trust,
was created as a Delaware business trust pursuant to a Trust Agreement
dated February 28, 1989 among The Standard Oil Company ("Standard
Oil"), BP Exploration (Alaska) Inc. (the "Company"), The Bank of New
York (The "Trustee") and The Bank of New York (Delaware), as
co-trustee. Standard Oil and the Company are indirect wholly owned
subsidiaries of the British Petroleum Company p.l.c. ("BP").
In 2000, the Company and certain 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 by the Company of its payment
obligations with respect to the Royalty Interest.
The trustees of the Trust are The Bank of New York, a New York
corporation authorized to do a banking business, and The Bank of New
York (Delaware), a Delaware banking corporation. The Bank of New York
(Delaware) serves as co-trustee in order to satisfy certain
requirements of the Delaware Trust Act. The Bank of New York alone is
able to exercise the rights and powers granted to the Trustee in the
Trust Agreement.
The Per Barrel Royalty in effect for any day is equal to the
price of West Texas Intermediate crude oil (the "WTI Price") for that
day less scheduled Chargeable Costs (adjusted in certain situations for
inflation) and Production Taxes (based on statutory rates then in
existence). For years subsequent to 2001, Chargeable Costs will be
reduced up to a maximum amount of $1.20 per barrel in each year if
additions to the Field's proved reserves do not meet certain specific
levels.
The Trust is passive, with the Trustee having only such powers
as are necessary for the collection and distribution of revenues, the
payment of Trust liabilities and the protection of the Royalty
Interest. The Trustee, subject to certain conditions, is obligated to
establish cash reserves and borrow funds to pay liabilities of the
Trust when they become due. The Trustee may sell Trust properties only
(a) as authorized by a vote of the Trust Unit holders, (b) when
necessary to provide for the payment of specific liabilities of the
Trust then due (subject to certain conditions) or (c) upon termination
of the Trust. Each Trust Unit issued and outstanding represents an
equal undivided share of beneficial interest in the Trust. Royalty
payments are received by the Trust and distributed to Trust Unit
holders, net of Trust expenses, in the month succeeding the end of each
calendar quarter. The Trust will terminate upon the first to occur of
the following events:
(a) On or prior to December 31, 2010: upon a vote of Trust Unit
holders of not less than 70% of the outstanding Trust Units.
37
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements (Continued)
(1) Formation of the Trust and Organization (Continued)
(b) After December 31, 2010: (i) upon a vote of Trust Unit holders
of not less than 60% of the outstanding Trust Units, or (ii)
at such time the net revenues from the Royalty Interest for
two successive years commencing after 2010 are less than
$1,000,000 per year (unless the net revenues during such
period 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 management 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 proves reserves attributable to the
Trust at the beginning of the fiscal year (approximately
94,000,000, 0 and 65,000,000 barrels of estimated proved
reserves were used to calculated the amortization of the
Royalty Interest for the years ended December 31, 2000, 1999
and 1998 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 years ended December 31, 2000, 1999 and 1998 was
$0.47, $0.47 and $8.23 respectively. The Trust evaluates
impairment of the Royalty Interest by comparing the
undiscounted cash flows expected to be realized from the
Royalty Interest to the carrying value, pursuant to Statement
of Financial Accounting Standards No. 121 ("SFAS 121")
"Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of". If the expected future
undiscounted cash flows are less than the carrying value, the
Trust recognizes an impairment loss for the difference between
the carrying value and the estimated fair value of the Royalty
Interest (see note 3).
While these statements differ from financial statements
prepared in accordance with 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, 2000 and 1999, cash equivalents consist of
US treasury bills with an initial term of less than three months. All
interest income earned on the treasury bills are reinvested.
The conveyance of the Royalty Interest by Standard Oil to the
Trust was accounted for as a purchase transaction. On February 28,
1989, Standard Oil sold 13,360,000 Trust Units to a group of
institutional investors for $334 million in a private placement. For
financial reporting purposes, the Trust's management valued the
remaining Trust Units owned by Standard Oil (8,040,000 units) at a per
unit value equivalent to the amount paid by the investors in the
private placement.
38
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements (Continued)
(2) Basis of Accounting (Continued)
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, 2000
and 1999 (in thousands):
2000 1999
--------- ---------
Royalty Interest $ 535,000 535,000
Less: Accumulated amortization (341,397) (338,886)
Impairment write-down (173,518) (173,518)
--------- ---------
$ 20,085 22,596
========= =========
During the fourth quarter of 1998, the Trust determined that the value
of the Royalty Interest was impaired as a result of the severe drop in
world oil prices during 1998 and reduced the unamortized recorded value
by $173,517,532 to its estimated fair value. The estimated fair value
was calculated by projecting expected future cash flows and discounting
them at a current rate that considered the risk inherent in the cash
flows.
(4) Income Taxes
The Trust files its federal tax return as a grantor trust
subject to the provisions of subpart E of Part I of Subchapter J of the
Internal Revenue Code of 1986, as amended, rather than as an
association taxable as a corporation. The Unit holders are treated as
the owners of Trust income and Corpus, and the entire taxable income of
the Trust will be reported by the Unit holders on their respective tax
returns.
If the Trust were determined to be an association taxable as a
corporation, it would be treated as an entity taxable as a corporation
on the taxable income from the Royalty Interest, the Trust Unit holders
would be treated as shareholders, and distributions to Trust Unit
holders would not be deductible in computing the Trust's tax liability
as an association.
39
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements (Continued)
(5) Summary of Quarterly Results (Unaudited)
A summary of selected quarterly financial information for the years
ended December 31, 2000 and 1999 is as follows (in thousands, except unit data):
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
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
1999
Royalty revenues $ -- -- 4,427 9,016
Interest income -- -- 13 47
Trust administrative expenses -- -- (625) (173)
Expenses reserve -- -- (250) (250)
-------- -------- -------- --------
Cash earnings -- -- 3,565 8,640
Cash distributions -- -- 3,565 8,640
Cash distributions per unit -- -- 0.166 0.404
(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, 2000 ($26.83 per barrel), December 31, 1999 ($25.60 per barrel),
and December 31, 1998 ($12.05 per barrel). Because the reserve volumes
attributable to the Trust are estimated using an allocation of reserve volumes
based on estimated future production and on the current WTI Price, a change in
the timing of estimated production or a change in the WTI price will result in a
change in the Trust's estimated reserve volumes. Therefore, the estimated
reserve volumes attributable to the Trust will vary if different production
estimates and prices are used.
40
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements (Continued)
(6) Supplemental Reserve Information and Standardized Measure of Discounted
Future Net Cash Flow Relating to Proved Reserves (Unaudited)(Continued)
In addition to production estimates and prices, reserve
volumes attributable to the Trust are affected by the amount of
Chargeable Costs that will be deducted in determining the Per Barrel
Royalty. The Royalty Interest includes a provision under which, in
years subsequent to 2001, if additions to the Field's proved reserves
from January 1, 1988 (after certain adjustments) do not meet certain
specified levels, Chargeable Costs will be reduced up to a maximum
amount of $1.20 per barrel in each year. Under the provisions of FASB
69, no consideration can be given to reserves not considered proved at
the present time. Accordingly, in estimating the reserve volumes
attributable to the Trust, Chargeable Costs were reduced by the maximum
amount in years subsequent to 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, 2000, 1999 and 1998 based on the Company's
latest reserve estimate at such time, the WTI Prices on December 31,
2000, 1999, and 1998 and a reduction in Chargeable Costs in years
subsequent to 1998, were estimated to be 91, 94 and 0 million barrels,
respectively (of which 84, 89, and 0 million barrels, respectively, are
proved developed).
The standardized measure of discounted future net cash flow
relating to proved reserves disclosure required by FASB 69 assigns
monetary amounts to proved reserves based on current prices. This
discounted future net cash flow should not be construed as the current
market value of the Royalty Interest. A market valuation determination
would include, among other things, anticipated price increases and the
value of additional reserves not considered proved at the present time
or reserves that may be produced after the currently anticipated end of
field life. At December 31, 2000, 1999, and 1998 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 $26.83, $25.60,
and $12.05, respectively, were as follows (in thousands):
December 31, December 31, December 31,
2000 1999 1998
------------ ------------ ------------
Future net cash flows $ 520,980 522,231 --
10% annual discount for
estimated timing of
cash flows (214,733) (217,504) --
--------- --------- ---------
Standardized measure of
discounted future net
cash flow relating to
proved reserves (a) $ 306,247 304,727 --
========= ========= =========
41
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements (Continued)
(6) Supplemental Reserve Information and Standardized Measure of Discounted
Future Net Cash Flow Relating to Proved Reserves (Unaudited)(Continued)
(a) The standardized measure of discounted future net cash flow
relating to proved reserves, estimated without reducing
Chargeable Costs in years subsequent to 1998, would be
$306,247,000, $304,727,000, and $0 at December 31, 2000, 1999
and 1998, respectively. The following are the principal
sources of the change in the standardized measure of
discounted future net cash flows (in thousands):
2000 1999 1998
--------- --------- ---------
Revisions of prior estimates:
Reserve volumes $ 2,913 330,031 116,023
WTI price 80,047 -- (228,764)
Chargeable costs - inflation (26,302) -- 5
Production taxes (10,571) -- 34,319
Other (2,187) 2 (780)
--------- --------- ---------
43,900 330,033 (79,197)
Royalty income received (b) (72,853) (25,306) (6,390)
Accretion of discount 30,473 -- 7,781
--------- --------- ---------
Net increase (decrease)
during the year $ 1,520 304,727 (77,806)
========= ========= =========
(b) Royalty income received for 2000, 1999 and 1998 includes the following:
Period October 1, 2000 through December 31, 2000 $ 19,932
Period October 1, 1999 through December 31, 1999 $ 12,105
Period October 1, 1998 through December 31, 1998 --
The above royalty income were received by the Trust in January 2000, 1999 and 1998, respectively.
The changes in quantities of proved oil and condensate were as follows (thousands of barrels):
Estimated net proved reserves of oil
and condensate at December 31, 1998 --
Production --
Change caused by prices/costs 93,582
---------
Estimated net proved reserves of oil
and condensate at December 31, 1999 93,582
Production (5,410)
Reserve estimate revisions 2,539
Change caused by prices/costs --
---------
Estimated net proved reserves of oil
and condensate at December 31, 2000 90,711
=========
Proved reserves:
December 31, 1998 --
=========
December 31, 1999 93,582
=========
December 31, 2000 90,711
=========
42
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 29, 2001, there were no persons known to the Trustee to be
the beneficial owners of more than five percent of the Units.
Unit Ownership of Management
Neither the Company, Standard Oil, nor BP owns any Units. No Units are
owned by The Bank of New York, as Trustee or in its individual capacity, or by
The Bank of New York (Delaware), as co-trustee or in its individual capacity.
Changes in Control
The Trustee knows of no arrangement, including the pledge of Units, the
operation of which may at a subsequent date result in a change in control of the
Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) FINANCIAL STATEMENTS
The following financial statements of the Trust are included in
Part II, Item 8:
Independent Auditors' Report
Statements of Assets, Liabilities and Trust Corpus as of
December 31, 2000 and 1999 Statements of Cash Earnings and
Distributions for the years ended December 31, 2000, 1999 and
1998 Statements of Changes in Trust Corpus for the years ended
December 31, 2000, 1999 and 1998 Notes to Financial Statements
43
(b) FINANCIAL STATEMENT SCHEDULES
All financial statement schedules have been omitted because they are
either not applicable, not required or the information is set forth in the
financial statements or notes thereto.
(c) EXHIBITS
4.1 BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among
The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New
York, Trustee, and F. James Hutchinson, Co-Trustee.
4.2 Overriding Royalty Conveyance dated February 27, 1989 between BP
Exploration (Alaska) Inc. and The Standard Oil Company.
4.3 Trust Conveyance dated February 28, 1989 between The Standard Oil
Company and BP Prudhoe Bay Royalty Trust.
4.4 Support Agreement dated as of February 28, 1989 among The British
Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard
Oil Company and BP Prudhoe Bay Royalty Trust.
27 Financial Data Schedule
(d) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the quarter ended December 31, 2000.
44
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 30, 2001
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.
45
INDEX TO EXHIBITS
Exhibit No. Description
----------- -----------
4.1* BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among
The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New
York, Trustee, and F. James Hutchinson, Co-Trustee.
4.2* Overriding Royalty Conveyance dated February 27, 1989 between BP
Exploration (Alaska) Inc. and The Standard Oil Company.
4.3* Trust Conveyance dated February 28, 1989 between The Standard Oil
Company and BP Prudhoe Bay Royalty Trust.
4.4* Support Agreement dated as of February 28, 1989 among The British
Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard
Oil Company and BP Prudhoe Bay Royalty Trust.
27 Financial Data Schedule. Filed herewith.
----------
* Incorporated by reference to the correspondingly numbered exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1996 (File No. 1-10243).
46