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, 2001
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
5 PENN PLAZA, 13TH FLOOR
NEW YORK, NEW YORK 10001
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (212) 896-7201
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
------------------- -----------------------------------------
UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
As of March 27, 2002, 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
$288,900,000.
Documents Incorporated by Reference: None
ITEM 8 OMITTED. TO BE FILED BY AMENDMENT.
TABLE OF CONTENTS
PART I
ITEM 1. Business..............................................................1
INTRODUCTION..........................................................1
THE TRUST.............................................................2
THE ROYALTY INTEREST..................................................7
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...........................................................28
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.................29
ITEM 6. Selected Financial Data..............................................30
ITEM 7. Trustee's Discussion And Analysis Of Financial Condition
And Results Of Operations............................................30
Item 7A. Quantitative and Qualitative Disclosure About Market Risk............32
ITEM 8. Financial Statements And Supplementary Data..........................33
ITEM 9. Changes In And Disagreements With Accountants On Accounting
And Financial Disclosure.............................................33
PART III
ITEM 10. Directors And Executive Officers Of The Registrant...................33
ITEM 11. Executive Compensation...............................................33
ITEM 12. Unit Ownership Of Certain Beneficial Owners And Management...........33
ITEM 13. Certain Relationships And Related Transactions.......................33
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, And Reports On Form 8-K.....34
SIGNATURES....................................................................35
INDEX TO EXHIBITS.............................................................36
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 5 Penn Plaza, New York, New York 10001 and its telephone
number is (212) 815-896-7201. 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.
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.
3
The interest conveyed to the Trust by the Conveyance is an overriding
royalty interest consisting of the right to receive a Per Barrel Royalty for
each barrel of Royalty Production. The meaning of these terms is more fully
described below under "THE ROYALTY INTEREST." The Trust does not have the right
to take oil and gas in kind.
The Royalty Interest constitutes a non-operational interest in
minerals. The Trust has no right to take over operations or to share in any
operating decision whatsoever with respect to the Company's working interest in
the Prudhoe Bay Unit. The Company is not obligated to continue to operate any
well or maintain in force or attempt to maintain in force any portion of its
working interest in the Prudhoe Bay Unit when, in its reasonable and prudent
business judgment such well or interest ceases to produce or is not capable of
producing oil or gas in paying quantities.
Under the terms of the Prudhoe Bay Unit Operating Agreement, if the Company
fails to pay any costs and expenses chargeable to the Company under the Prudhoe
Bay Unit Operating Agreement and the production of oil and condensate is
insufficient to pay such costs and expenses, the Royalty Interest is chargeable
with a pro rata portion of such costs and expenses and is subject to the
enforcement against it of liens granted to the operators of the Prudhoe Bay
Unit. However, in the Conveyance the Company agreed to pay timely all costs and
expenses chargeable to it and to ensure that no such costs and expenses will be
chargeable against the Royalty Interest. The Trust is not liable for any
expense, claim, damage, loss or liability incurred by the Company or others
attributable to the Company's working interest in the Prudhoe Bay Unit or to the
oil produced from it, and the Company has agreed to indemnify the Trust and hold
it harmless against any such impositions.
The Company has the right to amend or terminate the Prudhoe Bay Unit
Agreement, the Prudhoe Bay Unit Operating Agreement and any leases or
conveyances with respect to its working interest in the exercise of its
reasonable and prudent business judgment without liability to the Trust. The
Company also has the right to sell or assign all or any part of its working
interest in the Prudhoe Bay Unit, so long as the sale or assignment is expressly
made subject to the Royalty Interest and the terms and provisions of the
Conveyance.
Amendment of the Trust Agreement
The Trust Agreement may be amended without a vote of the holders of Units
to cure an ambiguity, to correct or supplement any provision of the Trust
Agreement that may be inconsistent with any other such provision or to make any
other provision with respect to matters arising under the Trust Agreement that
do not adversely affect the holders of Units. The Trust Agreement 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.
4
Resignation or Removal of Trustee
The Trustee may resign at any time or be removed with or without cause by
the holders of a majority of the outstanding Units. Its successor must be a
corporation organized and doing business under the laws of the United States,
any state thereof or the District of Columbia, authorized under such laws to
exercise trust powers, or a national banking association domiciled in the United
States, in either case having a combined capital, surplus and undivided profits
of at least $50,000,000 and subject to supervision or examination by federal or
state authorities. Unless the Trust already has a trustee that is a resident of
or has a principal office in the State of Delaware, then any successor trustee
will be such a resident or have such a principal office. No resignation or
removal of the Trustee shall become effective until a successor trustee shall
have accepted appointment.
Liabilities and Contingent Reserves
Because of the passive nature of the Trust's assets and the restrictions on
the power of the Trustee to incur obligations, the only liabilities incurred by
the Trust are routine administrative expenses, such as Trustee's fees, and
accounting, legal and other professional fees.
As discussed above, the Trustee may establish a cash reserve for the
payment of material liabilities of the Trust which may become due, if the
Trustee has determined that it is not practical to pay such liabilities out of
funds anticipated to be available for subsequent quarterly distributions and
that, in the absence of such a reserve, the trust estate is subject to the risk
of loss or diminution in value or The Bank of New York is subject to the risk of
personal liability for such liabilities. The Trustee is obligated to borrow
funds required to pay liabilities of the Trust when due, and to pledge or
otherwise encumber the Trust's assets, if it determines that the cash on hand is
insufficient to pay such liabilities and that it is not practical to pay such
liabilities out of funds anticipated to be available for subsequent quarterly
distributions. Borrowings must be repaid in full before any further
distributions are made to holders of Units. As previously described, certain
other necessary conditions must also be satisfied prior to the establishment of
a cash reserve or the Trust's borrowing of funds.
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.
5
Upon termination of the Trust, the Company will have an option to purchase
the Royalty Interest (for cash unless holders representing 70 percent of the
Units outstanding (60 percent if the decision to terminate the Trust is made
after December 31, 2010) authorize the sale for non-cash consideration and the
Trustee has received a ruling from the Internal Revenue Service or an opinion of
counsel to the effect that such non-cash sale will not adversely affect the
classification of the Trust as a "grantor trust" for federal income tax purposes
or cause the income from the Trust to be treated as unrelated business taxable
income for federal income tax purposes) at a price equal to the greater of (i)
the fair market value of the trust estate as set forth in an opinion of an
investment banking firm, commercial banking firm or other entity qualified to
give an opinion as to the fair market value of the assets of the Trust, or (ii)
the number of outstanding Units multiplied by (a) the closing price of Units on
the day of termination of the Trust on the stock exchange on which the Units are
listed, or (b) if the Units are not listed on any stock exchange but are traded
in the over-the-counter market, the closing bid price on the day of termination
of the Trust as quoted on the NASDAQ National Market System. If the Units are
neither listed nor traded in the over-the-counter market, the price will be the
fair market value of the trust estate as set forth in the opinion mentioned
above.
If the Company does not exercise its option, the Trustee will sell the
Trust properties pursuant to procedures or material terms and conditions
approved by the vote of holders of 70 percent of the outstanding Units (60
percent if the sale is made after December 31, 2010), unless the Trustee
determines that it is not practicable to submit such procedures or terms to a
vote of the holders of Units, and the sale is effected at a price which is at
least equal to the fair market value of the trust estate as set forth in the
opinion mentioned above and pursuant to terms and conditions deemed commercially
reasonable by the investment banking firm, commercial banking firm or other
entity rendering such opinion.
After satisfying all existing liabilities and establishing adequate
reserves for the payment of contingent liabilities, the Trustee will distribute
all available proceeds to the holders of Units.
In the Trust Agreement, holders of Units have waived the right to seek or
secure any portion or distribution of the Royalty Interest or any other asset of
the Trust or any accounting during the term of the Trust or during any period of
liquidation and winding up.
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.
6
THE ROYALTY INTEREST
The Royalty Interest is a property right under Alaska law which burdens
production, but there is no other security interest in the reserves or
production revenues to which the Royalty Interest is entitled. The royalty
payable to the Trust under the Royalty Interest for each calendar quarter is the
sum of the product of (i) the Royalty Production and (ii) the Per Barrel Royalty
for each day in the quarter. The payment under the Royalty Interest for any
calendar quarter may not be less than zero nor more than the aggregate value of
the total production of oil and condensate from the Company's working interest
in the Prudhoe Bay Unit for such calendar quarter, net of the State of Alaska
royalty and less the value of any applicable payments made to affiliates of the
Company.
Royalty Production
The "Royalty Production" for each day in a calendar quarter is 16.4246
percent of the first 90,000 barrels of the actual average daily net production
of oil and condensate for such quarter from the Prudhoe Bay (Permo-Triassic)
Reservoir and allocated to the oil and gas leases owned by the Company in the
Prudhoe Bay Unit as of February 28, 1989 or as modified thereafter by any
redetermination provided under the terms of the Prudhoe Bay Unit Operating
Agreement and the Prudhoe Bay Unit Agreement (the "Subject Leases"). The Royalty
Production is based on oil produced from the oil rim and condensate produced
from the gas cap, but not on gas production or natural gas liquids production.
The actual average daily net production of oil and condensate from the Subject
Leases for any calendar quarter is the total production of oil and condensate
for such quarter, net of the State of Alaska royalty, divided by the number of
days in such quarter.
Per Barrel Royalty
The "Per Barrel Royalty" in effect for any day is an amount equal to the
WTI Price for such day less the sum of (i) the product of the Chargeable Costs
multiplied by the Cost Adjustment Factor and (ii) Production Taxes. Based on the
WTI Price on December 31, 2001, current Production Taxes and Chargeable Costs
adjusted in accordance with the Conveyance, the Company estimates that Per
Barrel Royalty payments will continue through the year 2009.
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, 2001 were: $8.85 during 1997;
$9.30 during 1998; $9.80 during 1999; $10.00 during 2000; and $10.75 during
2001. Chargeable Costs for the calendar year ending December 31, 2002 and
subsequent years are shown in the following table:
For the Chargeable For the Chargeable
Year Ending Costs Per Year Ending Costs Per
December 31 Barrel December 31 Barrel
----------- ------ ----------- ------
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
2011 16.60
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 57.3 794.5
2001 20.5 815.0
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, 2001, the
cumulative additions to proved reserves allocated to the Subject Leases were
sufficient to prevent any reduction in Chargeable Costs during the years 2002
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 WTI Chargeable Adjustment Chargeable Production Per Barrel
Price Costs Factor Costs Taxes Royalty
----- ----- ------ ----- ----- -------
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
2001:
1st Qtr 28.83 10.75 1.354 14.55 3.44 10.84
2nd Qtr 27.92 10.75 1.368 14.71 3.29 9.92
3rd Qtr 26.82 10.75 1.367 14.69 3.13 9.00
4th Qtr 20.41 10.75 1.366 14.68 2.17 3.56
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
Services 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, 2001, approximately 10.3 billion STB of oil
and condensate had been produced from the Field. Field development is well
advanced with approximately $18.4 billion gross capital spent and a total of
about 2,168 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, 2001 is summarized in the following table:
Oil Rim Gas Cap
------- -------
BP.................................... 26.34% (a) 26.54% (b)
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, 2001 there were about 998 active producing oil wells, 32
gas reinjection wells, 39 water injection wells and 142 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 546 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)
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
2001 324.9 144.1 131.2 15.9
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 961.7 million STB as of December 31, 2001. 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 2013. The occurrence of major gas sales could
accelerate the time at which the Company's net production would fall below
90,000 barrels per day, due to the consequent decline in reservoir pressure. The
Company also projects continued economic production thereafter, at a declining
rate, until the year 2030; however, for the economic conditions and production
forecast as of December 31, 2001, it is estimated that royalty payments will
cease following the year 2009.
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, 2001 were 43.2 million barrels of oil and condensate. Using
procedures specified in Financial Accounting Standards Board Statement of
Financial Standards No. 69, the Company calculated that as of December 31, 2001
production of oil and condensate from the proved reserves allocated to the Trust
will result in estimated future net revenues to the Trust of $64.6 million, with
a present value of $47 million. The Company's estimates of proved reserves and
the estimated future net revenues from the Prudhoe Bay Unit have been reviewed
by Miller and Lents, Ltd., independent oil and gas consultants, as set forth in
their report following this section.
There is no precise method of forecasting the allocation of reserve volumes
between the Company and the Trust. The Royalty Interest is not a working
interest and the Trust is not entitled to receive any specific volume of
reserves from the Field. Rather, reserve volumes attributable to the Trust at
any given date are estimated by allocating to the Trust its share of estimated
future production from the Field based on WTI Prices and other economic
parameters in effect on the date of the evaluation.
The following table shows the net remaining proved reserves of oil and
condensate allocated to the Subject Leases, the net proved reserves allocated to
the Trust, and the WTI Prices on the dates indicated:
Net Proved Reserves
------------------------------------ WTI Price
December 31 Subject Leases (a) Trust (b) Per Barrel
----------- ------------------ --------- ----------
(Million STB)
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
2001 961.7 43.2 19.78
-------------
(a) Includes proved undeveloped reserves of 190.2 million STB at December 31,
1997; 109.8 million STB at December 31, 1998; 108 million STB at December
31, 1999; 137.3 million STB at December 31, 2000; and 112.5 STB at December
31, 2001.
18
(b) Includes proved undeveloped reserves of 1.3 million STB at December 31,
1997; 4.5 million STB at December 31, 1999; and 6.4 million STB at December
31, 2000. No proved undeveloped reserves were attributable to the Trust at
December 31, 1998 and December 31, 2001.
The reserve volumes attributable to the Trust are estimated using an
allocation of reserve volumes based on estimated future production and the
current WTI Price, and assume no future movement in the Consumer Price Index and
no future additions by the Company of proved reserves. The estimated reserve
volumes attributable to the Trust will vary if different estimates of
production, prices and other factors are used. Even if expected reservoir
performance does not change, the estimated reserves, economic life, and future
revenues attributable to the Trust may change significantly in the future. This
may result from changes in the WTI Price or from changes in other prescribed
variables utilized in calculations defined by the Overriding Royalty Conveyance.
See Note 6 of the Notes to Financial Statements in Item 8.
The Company is under no obligation to make investments in development
projects which would add additional non-proved resources to proved reserves and
cannot make such investments without the concurrence of the Prudhoe Bay Unit
working interest owners. However, several such investments which would augment
Prudhoe Bay projects are already in progress. These include additional drilling,
water flood expansions and miscible injection continuation/expansion projects.
Other possible investments could include expanded gas cycling, miscible/water
flood infill drilling, miscible injection supply increases to peripheral areas,
heavy oil tar recovery and development of the smaller reservoirs. While there is
no assurance that the Prudhoe Bay Unit working interest owners will make any
such investments they do regularly assess the technical and economic
attractiveness of implementing further projects to increase Prudhoe Bay Unit
proved reserves.
In the event of changes in the Company's current assumptions, oil and
condensate recoveries may be reduced from the current estimates, unless recovery
projects other than those included in the current estimates are implemented.
19
INDEPENDENT OIL AND GAS CONSULTANTS' REPORT
[LETTERHEAD OF]
MILLER AND LENTS, LTD. [Names Omitted]
INTERNATIONAL OIL AND GAS CONSULTANTS
TWENTY-SEVENTH FLOOR
1100 LOUISIANA
HOUSTON, TEXAS 77002-5216
TELEPHONE 713 651-9455
TELEFAX 713 654-9914
email: mail@millerand lents.com
February 20, 2002
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street, Floor 21 West
New York, New York 10286
Re: Estimates of Proved Reserves, Future Production Rates, and
Future Net Revenues for the BP Prudhoe Bay Royalty Trust As
of December 31, 2001
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, 2001. Additionally, we reviewed calculations of the
resulting Estimated Future Net Revenues and Present Value of Estimated Future
Net Revenues attributable to the BP Prudhoe Bay Royalty Trust.
The estimates and calculations reviewed are summarized in the report
prepared by BP Exploration (Alaska) Inc. and transmitted with a cover letter
dated February 11, 2002 addressed to Ms. Marie E. Trimboli of The Bank of New
York and signed by Mr. Neil McCleary. Reviews were also performed by Miller and
Lents, Ltd. during this year or in previous years of (1) the procedures for
estimating and documenting Proved Reserves, (2) the estimates of in place
reservoir volumes, (3) the estimates of recovery factors and production profiles
for the various areas, pay zones, projects, and recovery processes that are
included in the estimate of Proved Reserves, (4) the production strategy and
procedures for implementing that strategy, (5) the sufficiency of the data
available for making estimates of Proved Reserves and production profiles, and
(6) pertinent provisions of the Prudhoe Bay Unit Operating Agreement, the Issues
Resolution Agreement, the Overriding Royalty Conveyance, the Trust Conveyance,
the BP Prudhoe Bay Royalty Trust Agreement, and other related documents
referenced in the Form F-3 Registration Statement filed with the Securities and
Exchange Commission on August 7, 1989, by BP Exploration (Alaska) Inc.
20
Proved Reserves were estimated by BP Exploration (Alaska) Inc. in
accordance with the definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a). Estimated Future Net Revenues and Present Value of
Estimated Future Net Revenues are not intended and should not be interpreted to
represent fair market values for the estimated reserves.
The Prudhoe Bay (Permo Triassic) Reservoir is defined in the Prudhoe Bay
Unit Operating Agreement. The Prudhoe Bay Unit is an oil and gas unit situated
on the North Slope of Alaska. The BP Prudhoe Bay Royalty Trust is entitled to a
royalty payment on 16.4246 percent of the first 90,000 barrels of the actual
average daily net production of oil and condensate for each calendar quarter
from the BP Exploration (Alaska) Inc. working interest as defined in the
Overriding Royalty Conveyance. The payment amount depends upon the Per Barrel
Royalty which in turn depends upon the West Texas Intermediate Price, the
Chargeable Costs, the Cost Adjustment Factor, and Production Taxes, all of which
are defined in the Overriding Royalty Conveyance. "Barrel" as used herein means
Stock Tank Barrel as defined in the Overriding Royalty Conveyance.
Our reviews do not constitute independent estimates of the reserves and
annual production rate forecasts for the areas, pay zones, projects, and
recovery processes examined. We relied upon the accuracy and completeness of
information provided by BP Exploration (Alaska) Inc. with respect to pertinent
ownership interests and various other historical, accounting, engineering, and
geological data.
As a result of our cumulative reviews, based on the foregoing, we conclude
that:
1. A large body of basic data and detailed analyses are available and
were used in making the estimates. In our judgment, the quantity and
quality of currently available data on reservoir boundaries, original
fluid contacts, and reservoir rock and fluid properties are sufficient
to indicate that any future revisions to the estimates of total
original in place volumes should be minor. Furthermore, the data and
analyses on recovery factors and future production rates are
sufficient to support the Proved Reserves estimates.
2. The methods and procedures employed to accumulate and evaluate the
necessary information and to estimate, document, and reconcile
reserves, annual production rate forecasts, and future net revenues
are effective and are in accordance with generally accepted geological
and engineering practice in the petroleum industry.
3. Based on our limited independent tests of the computations of
reserves, production flowstreams, and future net revenues, such
computations were performed in accordance with the methods and
procedures described to us.
4. The estimated net remaining Proved Reserves attributable to the BP
Prudhoe Bay Royalty Trust as of December 31, 2001, of 43.2 million
barrels of oil and condensate are, in the aggregate, reasonable. All
of the 43.2 million barrels of Total Proved Reserves are Proved
Developed Reserves. Future production of Proved Undeveloped Reserves
does not affect the Trust's Proved Reserves because, under economic
assumptions as of December 31, 2001, the potential impact of such
production to the Trust occurs after the time when the Per Barrel
Royalty becomes zero.
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, 2001,
production of the Proved Reserves will result in Estimated Future Net
Revenues of $64.6 million and Present Value of Estimated Future Net
Revenues of $47.0 million to the BP Prudhoe Bay Royalty Trust. These
estimates are reasonable.
21
6. BP Exploration (Alaska) Inc. estimated that, as of December 31, 2001,
815.0 million barrels of Proved Reserves have been added to Current
Reserves. This estimate is reasonable. Current Reserves are defined in
the Overriding Royalty Conveyance as net Proved Reserves of 2,035.6
million barrels as of December 31, 1987. Net additions to Proved
Reserves after December 31, 1987 affect the Chargeable Costs that are
used to calculate the Per Barrel Royalty paid to the BP Prudhoe Bay
Royalty Trust.
7. The BP Exploration (Alaska) Inc. projection that its net production of
oil and condensate from Proved Reserves will continue at an average
rate exceeding 90,000 barrels per day until the year 2013 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 $19.78 per barrel on
December 31, 2001, current Production Taxes, and the Chargeable Costs
adjusted as prescribed by the Overriding Royalty Conveyance, the
projection that royalty payments will continue through the year 2009
is reasonable. BP Exploration (Alaska) Inc. expects continued economic
production at a declining rate through the year 2030; however, for the
economic conditions and production forecast as of December 31, 2001,
the Per Barrel Royalty will be zero following the year 2009.
Therefore, no reserves are currently attributed to the BP Prudhoe Bay
Royalty Trust after that date.
9. Even if expected reservoir performance does not change, the estimated
reserves, economic life, and future revenues attributable to the BP
Prudhoe Bay Royalty Trust may change significantly in the future. This
may result from changes in the West Texas Intermediate Price or from
changes in other prescribed variables utilized in calculations defined
by the Overriding Royalty Conveyance.
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
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., 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
William P. Koza
Vice President
[STATE OF TEXAS
WILLIAM P. KOZA
58894
REGISTERED
PROFESSIONAL ENGINEER]
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.
26
Taxation of Foreign Unit Holders
Generally, a holder of Units who is a nonresident alien individual or which
is a foreign corporation (a "Foreign Taxpayer") is subject to tax of on the
gross income produced by the Royalty Interest at a rate equal to 30 percent (or
at a lower treaty rate, if applicable). This tax is withheld by the Trustee and
remitted directly to the United States Treasury. A Foreign Taxpayer may elect to
treat the income from the Royalty Interest as effectively connected with the
conduct of a United States trade or business under Internal Revenue Code section
871 or section 882, or pursuant to any similar provisions of applicable
treaties. If a Foreign Taxpayer makes this election, it is entitled to claim all
deductions with respect to such income, but a United States federal income tax
return must be filed to claim such deductions. This election once made is
irrevocable unless an applicable treaty allows the election to be made annually.
Section 897 of the Internal Revenue Code and the Treasury Regulations
thereunder treat the Trust as if it were a United States real property holding
corporation. Foreign holders owning more than five percent of the outstanding
Units are subject to United States federal income tax on the gain on the
disposition of their Units. Foreign Unit holders owning less than five percent
of the outstanding Units are not subject to United States federal income tax on
the gain on the disposition of their Units, unless they have elected under
Internal Revenue Code section 871 or section 872 to treat the income from the
Royalty Interest as effectively connected with the conduct of a United States
trade or business.
If a Foreign person is a corporation which made an election under Internal
Revenue Code section 882(d), the corporation would also be subject to a 30
percent tax under Internal Revenue Code section 884. This tax is imposed on U.S.
branch profits of a foreign corporation that are not reinvested in the U.S.
trade or business. This tax is in addition to the tax on effectively connected
income. The branch profits tax may be either reduced or eliminated by treaty.
Sale of Units
Generally, a Unit holder will realize gain or loss on the sale or exchange
of his Units measured by the difference between the amount realized on the sale
or exchange and his adjusted basis for such Units. Gain on the sale of Units by
a holder that is not a dealer with respect to such Units will generally be
treated as capital gain. However, pursuant to Internal Revenue Code section
1254, certain depletion deductions claimed with respect to the Units must be
recaptured as ordinary income upon sale or disposition of such interest.
Backup Withholding
A payor must withhold 31 percent of any reportable payment if the payee
fails to furnish his taxpayer identification number ("TIN") to the payor in the
required manner or if the Secretary of the Treasury notifies the payor that the
TIN furnished by the payee is incorrect. Unit holders will avoid backup
withholding by furnishing their correct TINs to the Trustee in the form required
by law.
State Income Taxes
Unit holders may be required to report their share of income from the Trust
to their state of residence or commercial domicile. However, only corporate Unit
holders will need to report their share of income to the State of Alaska. Alaska
does not impose an income tax on individuals or estates and trusts. All Trust
income is Alaska source income to corporate Unit holders and should be reported
accordingly.
27
ITEM 2. PROPERTIES
Reference is made to Item 1 for the information required by this item.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS
None.
28
PART II
ITEM 5. MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS
The Units are listed and traded on the New York Stock Exchange under the
symbol BPT. The following table shows the high and low sales prices per Unit on
the New York Stock Exchange and the cash distributions paid per Unit, for each
calendar quarter in the two years ended December 31, 2000 and 2001.
Distributions
High Low Per Unit
---- --- --------
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
2001:
First Quarter $10 5/8 $ 8 9/16 $0.924
Second Quarter 12 7/16 8 5/16 0.662
Third Quarter 14 15/16 10 15/16 0.611
Fourth Quarter 15 13/32 11 1/2 0.573
As of December 31, 2001, 21,400,000 Units were outstanding and were held by
973 holders of record.
Future payments of cash distributions are dependent on such factors as the
prevailing WTI Price, the relationship of the rate of change in the WTI Price to
the rate of change in the Consumer Price Index, the Chargeable Costs, the rates
of Production Taxes prevailing from time to time, and the actual production from
the Prudhoe Bay Unit. See "THE ROYALTY INTEREST" in Item 1.
29
ITEM 6. SELECTED FINANCIAL DATA
The following table presents in summary form selected financial information
regarding the Trust.
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(In thousands, except per Unit amounts)
Royalty revenues $ 59,934 65,026 13,443 15,163 44,582
Interest income 70 92 60 17 21
Trust administration expenses 724 732 798 614 845
Expenses reserve 0 500 500 0 0
-------- ------ ------ ------ ------
Cash earnings $ 59,280 63,886 12,205 14,566 43,758
Cash distributions $ 59,319 63,838 12,205 14,566 43,758
Cash distributions per unit $ 2.772 2.983 0.570 0.681 2.045
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.
30
The decline in WTI Prices during the fourth quarter of 1998 and the first
quarter of 1999 resulted in the Trust not receiving quarterly distributions
during the first and second quarters of 1999. See "THE ROYALTY INTEREST - Per
Barrel Royalty Calculations. Upon the resumption of distributions in the third
quarter of 1999, resulting from 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 the 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, and any earning on investment
of the cash reserve, are income to the holders of the Units and must be reported
by the holders of the Units, even if such amounts are used to repay borrowings
or increase the cash reserve and are not distributed to 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, 2001, 2000 and 1990 are attributable to the
Company's operations during the twelve-month periods ended September 30, 2001,
2000 and 1999, 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 2013, 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.
31
During the year 2001 and the period of 2002 up to the date 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 the remainder of 2002 will depend on WTI Prices prevailing during the
remainder of the year.
2001 compared to 2000
Royalty revenues and cash distributions in 2001 decreased by approximately
7.8% and 7.1%, respectively, from 2000. Although the average WTI Price during
the 12 months ended September 30, 2001 increased by about 1.4% from the average
price during the same period in 2000, the increase was offset by an increase of
approximately 9.7% in Adjusted Chargeable Costs, primarily as a result of the
scheduled increase in Chargeable Costs from $10.00 per barrel to $10.75 per
barrel in the first quarter of 2001 and continued increases in the Cost
Adjustment Factor (see "THE ROYALTY INTEREST-Per Barrel Royalty Calculations" in
Item 1).
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 royalty revenues the
Trust administration expense decreased to 1.1% from 5.9% in 1999.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable.
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
[TO BE FILED BY AMENDMENT]
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 27, 2002, 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.
33
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:
[TO BE FILED BY AMENDMENT]
(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.
(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, 2001.
34
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 29, 2002
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.
35
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.
------------
* 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).
36