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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, 1993
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-10243
BP PRUDHOE BAY ROYALTY TRUST
(Exact name of registrant as specified in its charter)
DELAWARE 13-6943724
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
THE BANK OF NEW YORK, TRUSTEE
101 BARCLAY STREET, 21ST FLOOR WEST
NEW YORK, NEW YORK 10286
(Address of principal executive offices) (Zip Code)
Registrants telephone number, including area code: (212) 815-5092
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange On Which Registered
------------------- -----------------------------------------
UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. YES X No
-- --
As of March 14, 1994, 21,400,000 Units of Beneficial Interest were
outstanding, and the aggregate market value of Units (based upon the
closing price of the Units on the New York Stock Exchange as reported in
The Wall Street Journal) held by nonaffiliates was approximately
$524,300,000.
Documents Incorporated by Reference: None
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TABLE OF CONTENTS
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PART I
ITEM 1-Business................................................1
Description of the Trust.....................................1
Description of the Trust Units and the Trust Agreement.......3
Creation and Organization of the Trust....................3
Assets of the Trust.......................................3
Liability of the Trust....................................3
Duties and Limited Powers of Trustee......................3
Liabilities of Trustee....................................5
Resignation or Removal of Trustee.........................5
Duration of Trust.........................................6
Voting Rights of Holders of Trust Units...................7
Trust Units...............................................8
Distributions of Income...................................9
Transfers.................................................9
Mutilated, Destroyed, Lost or Stolen Certificates........10
Reports to Holders of Trust Units........................10
Liability of Holders of Trust Units......................11
Possible Divestiture of Trust Units......................11
Additional Conveyances...................................12
Description of the Royalty Interest.........................13
Per Barrel Royalty ......................................14
WTI Price ...............................................14
Chargeable Costs ........................................15
Cost Adjustment Factor ..................................17
Production Taxes ........................................18
Royalty Production ......................................18
Calculation of Royalty Amount ...........................18
Minimum Royalty .........................................19
Potential Conflicts of Interest
between the Company and Trust ...........................19
Description of the BP Support Agreement ....................19
Description of the Property ................................20
Background ..............................................20
Geology .................................................21
Hydrocarbons in Place ...................................21
Prudhoe Bay Unit Operation and Ownership ................22
Oil Rim Redetermination .................................22
Production and Reserves .................................24
Report of Miller and Lents, Ltd., Independent
Petroleum Consultants ...................................26
Reservoir Management ....................................33
Transportation of Prudhoe Bay Oil .......................33
Historical Production of Oil and Condensate ............35
Industry Conditions ........................................35
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Certain Tax Considerations .................................36
Employees ...............................................36
Federal Income Tax ......................................36
Classification of the Trust ........................36
Taxation of the Trust ..............................36
Taxation of Trust Unit Holders .....................37
Taxation of Nonresident Alien Individuals,
Partnerships and Foreign Corporations ..............38
Sale of Trust Units .....................................39
Backup Withholding .................................39
Reports ............................................39
State Income Taxes ......................................39
ITEM 2-Properties ............................................39
ITEM 3-Legal Proceedings .....................................39
ITEM 4-Submission of Matters to a Vote of Unit Holders .......39
PART II
ITEM 5-Market for Trust Units ................................40
ITEM 6-Selected Financial Data ...............................40
ITEM 7-Management's Discussion and Analysis of Financial
Condition and Results of Operations ...................41
ITEM 8-Financial Statements and Supplementary Data ...........45
ITEM 9-Changes In Accountants ................................58
PART III
ITEM 10-Directors and Executive Officers .....................58
ITEM 11-Executive Compensation ...............................58
ITEM 12-Unit Ownership .......................................58
ITEM 13-Certain Relationships and Related Transactions .......59
PART IV
ITEM 14-Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ..............................60
SIGNATURE ....................................................62
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PART I
ITEM 1. BUSINESS
DESCRIPTION OF THE TRUST
BP Prudhoe Bay Royalty Trust (the "Trust"), a grantor trust, was
created as a Delaware business trust. The Trust has been established by
The Standard Oil Company ("Standard Oil") and is administered by The Bank
of New York, as trustee (collectively with the co-trustee located in
Delaware, the "Trustee"), pursuant to the BP Prudhoe Bay Royalty Trust
Agreement dated February 28, 1989 by and among Standard Oil, BP Exploration
(Alaska) Inc. (the "Company") and the Trustee (the "Trust Agreement"). The
Company and Standard Oil are indirect, wholly owned subsidiaries of The
British Petroleum Company p.l.c. ("BP"). The Trustee's offices are located
at 101 Barclay Street, New York, New York 10286 and its telephone number is
(212) 815-5092.
Upon creation of the Trust, the Trust acquired an overriding royalty
interest (the "Royalty Interest"), which entitles the Trust to a Per Barrel
Royalty, as defined herein, on 16.4246% of the first 90,000 barrels of the
average actual daily net production of oil and condensate per quarter (the
"Royalty Production") from the Company's working interest in the Prudhoe
Bay Unit (the "PBU"). The Royalty Interest was conveyed to Standard Oil
pursuant to the terms of an Overriding Royalty Conveyance dated February
27, 1989 (the "Overriding Conveyance") and from Standard Oil to the Trust
by a Trust Conveyance dated February 28, 1989 (the "Trust Conveyance").
The Overriding Conveyance and the Trust Conveyance are herein collectively
referred to as the "Conveyance". The Royalty Interest is free of any
exploration and development expenditures. 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 Trust has been formed under
the Delaware Trust Act, which entitles holders of the Units of Beneficial
Interest (the "Trust Units") to the same limitation of personal liability
as stockholders of a corporation are afforded under Delaware law. The
Trust Units evidence undivided interests in the Trust and are listed on the
New York Stock Exchange under the ticker symbol "BPT".
The Trust Units are not an interest in or obligation of the Company,
Standard Oil or BP. The ultimate value of the Royalty Interest will be
dependent on the Royalty Production and the Per Barrel Royalty for each
day. The "Per Barrel Royalty" for any day will equal the per barrel price
of West Texas Intermediate crude oil, less scheduled chargeable costs, as
adjusted, and production taxes. See "Description of the Royalty Interest."
In certain circumstances, the Royalty Interest provided for a minimum
royalty payment of $8.92 per barrel of Royalty Production, if any, from the
PBU for each quarter through September 30, 1991; for all quarters
thereafter there is no minimum royalty payment. Pursuant to a Support
Agreement among BP, the Company, Standard Oil and the Trust, BP has
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guaranteed the performance by the Company of its payment obligations with
respect to the Royalty Interest.
The only assets of the Trust are (i) the Royalty Interest assigned to
the Trust and, (ii) from time to time, cash reserves and cash equivalents
being held by the Trustee for distribution. Subject to compliance with
certain conditions, additional royalty interests may be assigned to the
Trust. See "Description of the Trust Units and the Trust Agreement-
Additional Conveyances."
The value of the Trust Units is substantially dependent upon estimates
of proved reserves, production and the value of oil. 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. See "Report of Miller and Lents, Ltd.", independent petroleum
consultants, included herein.
The Company shares control of the operation of the PBU with the other
working interest owners, and has no obligation to continue production from
the PBU or to maintain production at any level and may interrupt or
discontinue production at any time. In addition, the operation of the PBU
is subject to normal operating hazards incident to the production and
transportation of oil in Alaska. In the event of damage to the PBU 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 financial statements of the Trust contained in this Annual Report
on Form 10-K include information regarding amounts distributed to Trust
Unit holders with respect to 1993, 1992, and 1991. This Annual Report also
includes information with respect to 1993 production and production in past
periods. Amounts distributed with respect to 1993, 1992, and 1991,
production in 1993 and in the past, and the most recent estimates of proved
reserves attributable to the Trust are not indicative of amounts to be
distributed in the future.
The following information is subject to the detailed provisions of the
Trust Agreement, the Overriding Conveyance, and the Trust Conveyance.
The provisions governing the Trust are complex and extensive, and no
attempt has been made below to describe all of such provisions. The
following is a general description of the basic framework of the Trust and
reference is made to the Trust Agreement for detailed provisions concerning
the Trust.
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DESCRIPTION OF THE TRUST UNITS AND THE TRUST AGREEMENT
CREATION AND ORGANIZATION OF THE TRUST
The Trust holds the Royalty Interest pursuant to the terms of the
Trust Agreement and the Conveyance, subject to the laws of the States of
Alaska and Delaware. The beneficial interest in the Trust created by the
Trust Agreement is divided into equal undivided portions called Trust
Units. See the discussion below under "Trust 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.
ASSETS OF THE TRUST
The Royalty Interest is the only asset of the Trust, other than cash
being held for the payment of expenses and liabilities and for distribution
to the holders of Trust Units. See "Duties and Limited Powers of Trustee".
LIABILITY OF THE TRUST
Because of the passive nature of the Trust's assets and the
restrictions on the power of the Trustee to incur obligations, it is
anticipated that the only liabilities the Trust will incur will be those
for routine administrative expenses, such as Trustee's fees, and
accounting, legal and other professional fees. However, if a court were to
hold that the Trust is an association taxable as a corporation, as more
fully discussed in "Certain Tax Considerations-Federal Income Tax-
Classification of the Trust", the Trust would incur substantial income tax
liabilities in addition to its other expenses. In addition, if the Trust
were required to make allocations of income and deductions other than on a
quarterly basis, the administrative expenses of the Trust might increase.
See "Certain Tax Considerations-Federal Income Tax-Taxation of Trust Unit
Holders". The administrative fees and expenses of the Trust for the years
ended December 31, 1993, 1992, 1991, 1990 and 1989 were approximately
$555,000, $415,000, $415,000, $460,000 and $170,000, respectively,
including fees paid by the Trust to accountants, petroleum consultants and
counsel. Future administrative fees and expenses will depend, among other
things, on the number of Trust Unit holders and the fees of accountants,
petroleum consultants, counsel and other experts, if any, engaged by 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 basic function of the Trustee is
to collect income from the Royalty Interest, to pay out of the Trust's
income and assets all expenses, charges and obligations and to pay
available cash to holders of Trust Units.
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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 on subsequent
Quarterly Record Dates (as defined below) out of funds anticipated to be
available on such dates and that, in the absence of such 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,
provided that, except in certain limited circumstances, it has received an
opinion of counsel to the effect that the establishment and maintenance of
such reserve will not adversely affect the classification of the Trust as a
"grantor trust" for federal income tax purposes or cause the income from
the Trust to be treated as unrelated business taxable income for federal
income tax purposes. The Trustee is obligated, subject to certain
conditions, to borrow funds required to pay liabilities of the Trust, if
they become due, and 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 on subsequent
Quarterly Record Dates out of funds anticipated to be available on such
dates, provided that, except in certain limited circumstances, it has
received an opinion of counsel to the effect described above. Borrowings
must be repaid in full before any further distributions are made to holders
of Trust Units.
All distributable cash of the Trust will be distributed on a quarterly
basis. To date, and until certain requirements of the Trust Agreement are
met concerning the status of the assets of the Trust for purposes of
certain Department of Labor regulations, all distributions to Trust Unit
holders must be made as soon as practicable and the Trustee must hold cash
received uninvested pending such distribution. The Trustee is required to
invest any cash being held by it for distribution on the next distribution
date or being held by it as a reserve for liabilities in U.S. Obligations
or, if U.S. Obligations having a maturity date on the next distribution
date are not available, repurchase agreements with banks, including The
Bank of New York, secured by U.S. Obligations and meeting certain specified
requirements. Any U.S. Obligation or any such repurchase agreement must
mature on the next distribution date or on the due date of the liability
with respect to which the reserve is established, if known, and subject to
certain exceptions, will be held to maturity. The Trustee is required, in
certain circumstances, to invest the cash being held by it in an overnight
time deposit with a bank, including The Bank of New York. Amounts being
held by the Trustee after the date fixed for distribution of assets upon
termination of the Trust, however, must be held uninvested.
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, commercial or, with
certain exceptions, investment activity of any kind and from using any
portion of the assets of the Trust to acquire any oil and gas lease,
royalty or other mineral interest. The Trustee may sell Trust properties
only as authorized by a vote of the holders of Trust Units, or when
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necessary, to provide for the payment of specific liabilities of the Trust
then due (if, among other things, the Trustee determines that it is not
practicable to submit such sale to a vote of the holders of Trust Units,
and it receives an opinion of counsel to the effect that such sale will not
adversely affect the classification of the Trust as a "grantor trust" for
federal income tax purposes), or upon termination of the Trust. Pledges or
other encumbrances to secure borrowings are permitted without a vote of
holders of Trust Units if the Trustee determines such action is advisable.
Any sale of Trust properties must be for cash unless otherwise authorized
by the holders of Trust Units, and the Trustee is obligated to distribute
the available net proceeds of any such sale to the holders of Trust Units
after establishing reserves for liabilities of the Trust.
LIABILITIES OF TRUSTEE
Except in the circumstances described below, in which the Company will
indemnify the Trustee and The Bank of New York in its individual capacity,
the Trustee and The Bank of New York in its individual capacity will 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. The Trustee and
The Bank of New York in its individual capacity will be indemnified by the
Company for liabilities to the extent described above (a) whenever the
assets of the Trust are insufficient or not permitted by applicable law to
provide such indemnity and (b) after the termination of the Trust, to the
extent that the Trustee did not have knowledge or should not have
reasonably known of a potential claim against the Trustee for which a
reserve could have been established and used to satisfy such claim prior to
the final distribution of assets of the Trust upon its termination. In no
event will the Trustee be deemed to have acted negligently, fraudulently or
in bad faith if it takes or suffers action in good faith in reliance upon
and in accordance with the written advice of counsel or other experts.
The Trustee is not entitled to indemnification from the holders of
Trust Units except in certain limited circumstances related to the
replacement of mutilated, destroyed, lost or stolen certificates. In
addition, the Company has agreed to indemnify and hold the Trustee and the
Trust harmless from certain liabilities under the federal securities laws.
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 Trust 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
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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 such appointment.
DURATION OF TRUST
The Trust is irrevocable and the Company has no power to terminate the
Trust or, except with respect to certain corrective amendments agreed to by
the Trustee, to alter or amend the terms of the Trust Agreement. The Trust
will terminate upon the first to occur of the following events or times:
(a) upon a vote of holders of not less than 70% of the outstanding Trust
Units, on or prior to December 31, 2010, in accordance with the procedures
described under "Voting Rights of Holders of Trust Units" below, 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% of the
outstanding Trust Units. Upon the dissolution of the Trust, the Trustee
will continue to act in such capacity until completion of the winding up of
the affairs of the Trust. Upon termination of the Trust, the Trustee will
sell Trust properties in one or more sales for cash, unless holders
representing 70% of the Trust Units outstanding (60% if the decision to
terminate the Trust is made after December 31, 2010) authorize the sale for
a specified non-cash consideration in which event the Trustee may, but is
not obligated to, consummate such non-cash sale, but only if the Trustee
shall have received a ruling from the Internal Revenue Service (the "IRS")
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. Prior to such sale the Trustee will obtain an opinion of an
investment banking firm or other entity qualified to give such opinion as
to the fair market value of the assets of the Trust on the day of
termination of the Trust. The Trustee will effect any such sale pursuant
to procedures or material terms and conditions approved by the vote of
holders of 70% of the outstanding Trust Units (60% if the sale is made
after December 31, 2010) in accordance with the procedures described under
"Voting Rights of Holders of Trust Units" below, unless the Trustee
determines that it is not practicable to submit such procedures or terms to
a vote of the holders of Trust Units, and the sale is effected at a price
which is at least equal to the fair market value of the trust estate as set
forth in the opinion mentioned above and pursuant to terms and conditions
deemed commercially reasonable by the investment banking firm or other
entity rendering such opinion. Upon dissolution of the Trust, the Company
will have an option to purchase the Royalty Interest at a price equal to
the greater of (i) the fair market value of the trust estate as set forth
in the opinion mentioned above, or (ii) the number of then outstanding
Trust Units multiplied by (a) the closing price of Trust Units on the day
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of termination of the Trust on the stock exchange on which the Trust Units
are listed, or (b) if the Trust 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 National Market System of
the National Association of Securities Dealers Automated Quotation System.
If the Trust 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. 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 Trust Units on the date specified in a notice given by
the Trustee, which date will be no later than 10 days after delivery of
such notice.
The Trustee cannot predict what amount it will be able to receive for
the Trust's assets if the Trust terminates or the expenses which the Trust
may incur in attempting to sell the assets.
VOTING RIGHTS OF HOLDERS OF TRUST UNITS
Although holders of Trust 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
Trust Units or annual or other periodic reelection of the Trustee.
Meetings of holders of Trust Units may be called by the Trustee at any
time at its discretion and must be called by the Trustee at the written
request of holders of not less than 25% of the then outstanding Trust Units
or at the request of the Company or as may be required by law or applicable
regulation. The presence of a majority of the outstanding Trust Units is
necessary to constitute a quorum, and holders may vote in person or by
proxy.
Notice of any meeting of holders of Trust Units must be given not more
than 60 nor fewer than 10 days prior to the date of such meeting. The
notice must state the purpose or purposes of the meeting and no other
matter may be presented or acted upon at the meeting.
The Trust Agreement may be amended without a vote of the holders of
Trust 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 Trust Units.
The Trust Agreement may also be amended with the approval of a majority of
the outstanding Trust Units at any duly called meeting of holders of Trust
Units. However, no such amendment may alter the relative rights of Trust
Unit holders unless approved by the affirmative vote of 100% of the holders
of Trust Units and by the Trustee or reduce or delay the distributions to
the holders of Trust Units or effect certain other changes unless approved
by the affirmative vote of 80% of the holders of Trust Units and by the
Trustee. No amendment will be effective until the Trustee has received a
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ruling from the IRS 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.
Removal of the Trustee will require the affirmative vote of the
holders of a majority of the Trust Units represented at a duly called
meeting of the holders of Trust Units. A successor trustee may be
appointed by the holders of Trust Units at such meeting. If the Trustee
has given notice of its intention to resign, a successor trustee will be
appointed by the Company.
The sale of all or any part of the Royalty Interest must be authorized
by the affirmative vote of the holders of 70% of the outstanding Trust
Units (60% if such sale is to be effected after December 31, 2010),
provided 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 assets of the Trust, such sale may be
approved by the affirmative vote of holders of a majority of the
outstanding Trust Units. However, subject to certain conditions, the
Trustee may, without a vote of the holders of Trust Units, sell all or any
part of the Trust assets if necessary to provide for the payment of
specific liabilities of the Trust then due or upon termination of the
Trust. The Trust can be terminated by the holders of Trust Units only if
the termination is approved by the holders of 70% of the Trust Units (on or
prior to December 31, 2010) or of 60% of the Trust Units (after December
31, 2010). The Trust may also be terminated after December 31, 2010 if 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 have
been materially and adversely affected by an event constituting force
majeure.
The Company and Standard Oil will vote or cause to be voted any Trust
Units held of record or beneficially by the Company, Standard Oil or any
affiliate of either of them in the same proportion as the Trust Units voted
by other holders of Trust Units at such meeting.
TRUST UNITS
Each Trust Unit represents an equal undivided share of beneficial
interest in the Trust. Trust Units are evidenced by transferable
certificates issued by the Trustee. If at any time there is assigned to
the Trust an Additional Royalty Interest, the beneficial interest in the
Trust will thereafter be considered to be divided into a number of Trust
Units equal to the sum of the number of Trust Units existing prior to such
assignment and the number of Trust Units created upon such assignment. The
Trust Units will not represent an interest in or obligation of the Company,
Standard Oil or any of their respective affiliates. Except in the limited
circumstances described under "Additional Conveyances" each Trust Unit
will entitle its holder to the same rights as the holder of any other Trust
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Unit, and the Trust will have no other authorized or outstanding class of
equity securities. There are 21,400,000 Trust Units outstanding.
DISTRIBUTIONS OF INCOME
The Company will pay the Trust amounts due pursuant to the Royalty
Interest on a quarterly basis on the fifteenth day after the end of each
calendar quarter (or, if such day is not a business day, on the next
succeeding business day) unless due to applicable law or stock exchange
rules a different payment day is required. Distributions of Trust income
are currently made as soon as practicable after receipt of such amounts by
the Trustee. After certain requirements of the Trust Agreement concerning
the status of the assets of the Trust under certain Department of Labor
regulations are met, distributions of Trust income will be made on the
fifth day (or if such day is not a business day, on the next succeeding
business day) after the Trustee's receipt in same day finally collected
funds of amounts to be received on a Quarterly Record Date for each Quarter
(defined below) in each year during the term of the Trust. Such
distribution will be made to the person in whose name the Trust Unit (or
any predecessor Trust Unit) is registered at the close of business on the
immediately preceding January 15, April 15, July 15, or October 15 (or, if
such day is not a business day, on the next succeeding business day), as
the case may be, unless the Trustee determines that a different date is
required to comply with applicable law or stock exchange rules (each a
"Quarterly Record Date"). A "Quarter", for purposes of the Trust
Agreement, is a period of approximately three months beginning on the day
after a Quarterly Record Date and continuing through and including the next
succeeding Quarterly Record Date. The aggregate quarterly distribution of
income (the "Quarterly Income Amount") will be the excess of (i) revenues
from the Royalty Interest plus any decrease in cash reserves previously
established for estimated liabilities and any other cash receipts of the
Trust over (ii) the expenses and payments of liabilities of the Trust plus
any net increase in cash reserves for estimated liabilities. If prior to
the end of a Quarter the Trustee makes a determination of the Quarterly
Income Amount which it anticipates will be distributed to holders of Trust
Units on the Quarterly Record Date for such Quarter, based on notice
provided to the Trustee by the Company, and the Quarterly Income Amount is
not equal to the amount so determined due to late payment, the Trustee will
treat such amounts when received as if they were received on such Quarterly
Record Date. Payment of the respective pro rata portion of the aggregate
quarterly distribution of income to each holder of Trust Units will be made
by check mailed to each such holder, provided that holders of Trust Units
may arrange for payments of $100,000 or more to be made by wire transfer in
immediately available funds.
TRANSFERS
The Trustee acts as registrar and transfer agent for the Trust Units.
Subject to the limitations set forth below and to the limitation described
under "Additional Conveyances" below, Trust Units may be transferred by
surrender of the certificates duly endorsed, or accompanied by a written
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instrument of transfer, in form satisfactory to the Trustee, duly executed
by the holder of the Trust Unit or his attorney duly authorized in writing.
No service charge will be made for any registration of transfer of Trust
Units, but the Trustee may require the payment of a sum sufficient to cover
any tax or other governmental charge that may be imposed in connection with
any registration of transfer. Until a transfer is made in accordance with
the regulations prescribed by the Trustee, the Trustee may conclusively
treat as the owner of any Trust Unit, for all purposes, the holder shown by
its records (except in the event of a purchase by the Company or a designee
thereof of Trust Units subject to the Trustee's right of redemption, as
described under "Possible Divestiture of Trust Units" below). Any
transfer of a Trust Unit will vest in the transferee all rights of the
transferor at the date of transfer, except that the transfer of a Trust
Unit after the Quarterly Record Date for distribution will not transfer the
right of the transferor to such distribution. The Trustee is specifically
authorized to rely upon the application of Article 8 of the Uniform
Commercial Code, the Uniform Act for Simplification of Fiduciary Security
Transfers and other statutes and rules with respect to the transfer of
securities, each as adopted and then in force in the State of Delaware, as
to all matters affecting title, ownership, warranty or transfer of
certificates and the Trust Units represented thereby.
MUTILATED, DESTROYED, LOST OR STOLEN CERTIFICATES
If a mutilated certificate is surrendered to the Trustee, the Trustee
will execute and deliver in exchange therefor a new certificate. If there
shall be delivered to the Trustee evidence of the destruction, loss or
theft of a certificate and such security or indemnity as may be required to
hold the Trust and the Trustee harmless, then, in the absence of notice to
the Trustee that such certificate has been acquired by a bona fide
purchaser, the Trustee will execute and deliver, in lieu of any such lost,
stolen or destroyed certificate, a new certificate. In connection with the
issuance of any new certificates, the Trustee may require the payment of a
sum sufficient to cover any tax or other governmental charge that may be
imposed in relation thereto and any other expenses (including fees and
expenses of the Trustee) in connection therewith.
REPORTS TO HOLDERS OF TRUST UNITS
As promptly as practicable following the end of each calendar year,
but no later than 90 days thereafter, the Trustee will mail to each person
who was a holder of record at any time during such calendar year a report
containing sufficient information to enable holders of Trust Units to make
all 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 such calendar year. As promptly as practicable
following the end of each Quarter, but no later than 60 days following the
end of such Quarter, during the term of the Trust, the Trustee will mail a
report for such Quarter showing in reasonable detail on a cash basis the
assets and liabilities, receipts and disbursements and income and expenses
of the Trust and the Royalty Production for such Quarter to holders of
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Trust Units of record on the last Quarterly Record Date immediately
preceding the mailing thereof. Within 90 days following the end of each
calendar year, the Trustee will mail an annual report containing (a)
audited financial statements of the Trust, (b) a statement as to whether or
not all fees and expenses of the Trustee were calculated and paid in
accordance with the Trust Agreement, (c) such information as the Trustee
deems appropriate from a letter of the independent public accountants
engaged by the Trustee as to compliance with certain terms of the
Conveyance and any Additional Conveyances and computation of the amounts
payable to the Trust in respect of the Royalty Interest, (d) a letter of
the independent petroleum engineers engaged by the Trust setting forth a
summary of such firm's determinations regarding the Company's methods,
procedures and estimates referred to in the Conveyance concerning proved
reserves and other related matters, and (e) a copy of the latest annual
report with respect to the Trust Units filed with the Securities and
Exchange Commission (the "Commission") or information furnished to the
Trustee pursuant to the Conveyance, to holders of Trust Units of record on
the last Quarterly Record Date immediately preceding the mailing thereof.
The Trustee will mail to holders of Trust Units any other reports or
statements required to be provided to Trust Unit holders by applicable law
or governmental regulations or by the requirements of any stock exchange on
which the Trust Units may be listed.
In the Trust Agreement, holders of Trust 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.
LIABILITY OF HOLDERS OF TRUST UNITS
The Trust Agreement provides that the holders of Trust Units will, to
the full extent permitted by Delaware law, be entitled to the same
limitation of personal liability extended to stockholders of private
corporations for profit under Delaware law.
POSSIBLE DIVESTITURE OF TRUST UNITS
The Trust Agreement imposes no restrictions on nationality or other
status of the persons or other entities which are eligible to hold Trust
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
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of his Trust 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 Trust Units in accordance
with such notice, the Trustee shall have the right to redeem and shall
redeem at any time during the 90-day period following the termination of
the 30-day period specified in the notice, any Trust Unit not so
transferred for a cash price per unit equal to the closing price of the
Trust Units on the stock exchange on which the Trust Units are then listed
or, in the absence of any such listing, the closing bid price on the
National Market System of the National Association of Securities Dealers
Automatic Quotation System if the Trust Units are so quoted or, if not, the
mean between the closing bid and asked prices for the Trust 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 Trust
Units are neither listed nor traded in the over-the-counter market, the
price will be the fair market value of the Trust Units as determined by a
recognized firm of investment bankers or other competent advisor or expert.
(iii) The Trustee will cancel any Trust Unit redeemed by the Trustee
in accordance with the foregoing procedures.
(iv) The Trustee may, in its sole discretion, cause the Trust to
borrow any amount required to redeem the Trust Units.
If the purchase of Trust Units from an ineligible holder by the
Trustee would result in a non-exempt prohibited transaction" under the
Employee Retirement Income Security Act of 1974, as amended ("ERISA"), or
under the Internal Revenue Code of 1986, as amended (the "Code"), the Trust
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.
ADDITIONAL CONVEYANCES
Additional royalty interests ("Additional Royalty Interests")
identical in all respects to the initial Royalty Interest except for the
identity of the parties (other than the Trust) (provided that the entity
which will make payments to the Trust under any Additional Royalty Interest
is the same entity making payments to the Trust under the initial
Conveyance), the effective date (which must be on the first day of a
calendar quarter and must be the date of delivery thereof to the Trustee)
and the percentage set forth in the definition of Royalty Production in the
related additional conveyance, may be assigned by the Company or an
affiliate thereof to the Trust from time to time, through the execution of
additional conveyances (each an "Additional Conveyance"). In consideration
of the grant of an Additional Royalty Interest, the Trustee will issue to
the order of the Company or such affiliate, a number of Trust Units, not to
exceed a total of 18,600,000 additional Trust Units, equal to (i) the
product of (a) the percentage set forth in the definition of Royalty
Production in the related Additional Conveyance and (b) 21,400,000, (ii)
divided by 16.4246%. In connection with such issuance, the recipients of
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such Trust Units and their transferees will not be treated as holders of
Trust Units of record entitled to distributions with respect to the
Quarterly Income Amount for the Quarterly Record Date which occurs during
the month in which such Additional Conveyance is effective and will not be
entitled to transfer such Trust Units (other than to the Company or one of
its affiliates) on or prior to such Quarterly Record Date, and the
certificates representing such Trust Units will prominently so state.
The acceptance by the Trustee of any such assignment will be subject
to the conditions that the Trustee shall have received a ruling from the
IRS 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, and rulings from the IRS
or an opinion of counsel to the effect that such assignment will not cause
the income from the Trust to be treated as unrelated business taxable
income for federal income tax purposes, or the holders of Trust Units to
recognize income, gain or loss attributable to the Royalty Interest as a
result of such assignment, except to the extent of any gain or loss
attributable to any cash received by the Trust in connection with such
assignment.
In addition, the Trustee will require that the Company or its
affiliate contribute a cash reserve computed by reference to the value of
the cash reserve for future liabilities existing on the date the Additional
Conveyance is effective. The Trustee will invest any cash so contributed
as described under "Duties and Limited Powers of Trustee" above, and will
distribute the cash so contributed and any interest earned thereon to
holders of Trust Units of record on the Quarterly Record Date which occurs
during the month in which the related Additional Conveyance becomes
effective, except to holders of Trust Units issued upon the assignment of
the Additional Conveyance.
Any Additional Royalty Interest assigned to the Trust will constitute
a part of the trust estate and, to the extent permitted by law, will be
treated by the Trustee, together with the initial Royalty Interest and all
other Additional Royalty Interests previously assigned to the Trust, as
constituting one Royalty Interest held for the benefit of all holders of
Trust Units.
DESCRIPTION OF THE ROYALTY INTEREST
The Trust property consists of a Royalty Interest entitling the Trust
to a Per Barrel Royalty on 16.4246% of the first 90,000 barrels of the
average actual daily net production of oil and condensate per quarter (the
"Royalty Production") from the Company's working interest in the PBU.
There are 21,400,000 Trust Units outstanding. If additional Trust Units
are issued, the Royalty Interest percentage will be increased
proportionately. 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
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Endicott formations. The Company's average daily net production from its
working interest in the PBU during 1993 was approximately 417,700 barrels
of oil and condensate.
As is true of net profits royalty interests generally, the Royalty
Interest is a property right under applicable principles of 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 is the
product of the Royalty Production and the Per Barrel Royalty for each day.
PER BARREL ROYALTY
The Per Barrel Royalty in effect for any day will equal the WTI Price
for such day less the sum of (i) the product of the Chargeable Costs and
the Cost Adjustment Factor and (ii) Production Taxes.
WTI PRICE
The "WTI Price" for any trading day means (i) the latest price
(expressed in dollars per barrel) for West Texas Intermediate crude oil of
standard quality having a specific gravity of 40 degrees API for delivery
at Cushing, Oklahoma ("West Texas Crude"), quoted for such trading day by
the Dow Jones International Petroleum Report (which is published in The
Wall Street Journal) or if the Dow Jones International Petroleum Report
does not publish such quotes, then such price as quoted by Reuters, or if
Reuters does not publish such quotes, then such price as quoted in Platt's
Oilgram Price Report, or (ii) if for any reason such publications do not
publish such price, then the WTI Price will mean, until (i) is again
applicable, 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 petroleum trading company, in each case
unaffiliated with BP. Such major oil company, petroleum broker and
petroleum trading company must have substantial U.S. operations and will be
designated by the Company from time to time in an officer's certificate
delivered to the Trustee. 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 first for (i)
and then (ii) above, will mean such other light sweet domestic crude oil of
standard quality as is designated by the Company in an officer's
certificate delivered to the Trustee 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 will be the WTI Price for the next preceding day which
is a trading day.
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CHARGEABLE COSTS
The "Chargeable Costs" per barrel of Royalty Production were $4.50 per
barrel through December 31, 1991, $6.00 per barrel from January 1, 1992
through December 31, 1992, $6.75 per barrel from January 1, 1993 through
December 31, 1993 and will be the amount set forth in the following table
opposite the calendar year stated:
<TABLE>
<CAPTION>
For the Chargeable For the Chargeable
Year Ending Costs Per Year Ending Costs Per
December 31, Barrel December 31, Barrel
<S> <C> <C> <C>
1994 $ 8.00 2008 $13.00
1995 8.25 2009 13.25
1996 8.50 2010 14.50
1997 8.85 2011 16.60
1998 9.30 2012 16.70
1999 9.80 2013 16.80
2000 10.00 2014 16.90
2001 10.75 2015 17.00
2002 11.25 2016 17.10
2003 11.75 2017 17.20
2004 12.00 2018 20.00
2005 12.25 2019 23.75
2006 12.50 2020 and 26.50 increasing
2007 12.75 thereafter by $2.75
each year
thereafter
</TABLE>
Chargeable Costs are multiplied by the Cost Adjustment Factor as
defined below.
Chargeable Costs will be reduced up to a maximum of $1.20 per barrel
in any given year subsequent to 1995 based on the following tests of the
Company's additions of Proved Reserves to Current Reserves. Current
Reserves are defined as the Company's Proved Reserves of crude oil and
condensate as of December 31, 1987 (2035.6 million stock tank barrels
("STB")) and before taking into account any production therefrom and before
any reduction that may result from the creation of the Trust.
(a) If, by December 31, 1995, 100,000,000 or more STB of Proved
Reserves have not been added to Current Reserves, then for each year 1996
through 2000, inclusive, Chargeable Costs as set forth in the table above
shall be reduced, as of January 1 in each such year, by an amount equal to
the lesser of (A) $1.20 or (B) the product of $1.20 and a fraction, the
numerator of which shall be the difference between 100,000,000 STB of
Proved Reserves and the actual number of STB of Proved Reserves so added to
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Current Reserves from January 1, 1988 through December 31, 1995 and the
denominator of which shall be 100,000,000 STB of Proved Reserves. The
Company added approximately 42,000,000 STB to Proved Reserves during 1988,
approximately 45,500,000 STB during 1989, approximately 24,000,000 STB
during 1990, approximately 116,000,000 STB during 1991, approximately
144,000,000 STB during 1992 and approximately 206,000,000 STB during 1993.
(b) If between January 1, 1996 and December 31, 2000 an additional
200,000,000 STB of Proved Reserves (that is, 200,000,000 STB of Proved
Reserves in addition to the 100,000,000 STB of Proved Reserves that are
referred to in (a)) have not been added to Current Reserves, then for each
year from 2001 through 2005, inclusive, Chargeable Costs as set forth in
the table above shall be reduced, as of January 1 in each such year, by an
amount equal to the lesser of (A) $1.20 or (B) the product of $1.20 and a
fraction, the numerator of which shall be the difference between (1)
200,000,000 STB of Proved Reserves and (2) the sum of (i) the actual number
of STB of Proved Reserves so added to Current Reserves from January 1, 1996
through December 31, 2000 plus (ii) the excess, if any, of the number of
STB of Proved Reserves so added to Current Reserves from January 1, 1988
through December 31, 1995 over 100,000,000 STB of Proved Reserves (provided
that the sum of (i) and (ii) shall not exceed 200,000,000 STB of Proved
Reserves) and the denominator of which shall be 200,000,000 STB of Proved
Reserves.
(c) The tests set forth in (i) and (ii) below will be utilized to
calculate the reduction, if any, in Chargeable Costs for the year 2006 and
each year thereafter. If the calculation under one of such tests produces
a reduction in Chargeable Costs but the calculation under the other test
does not, the calculation that produces the reduction shall apply. In
applying the tests below, it is the intention of the Company that test (i)
allow as a credit toward the 400,000,000 STB of Proved Reserves that must
be added to Current Reserves during the period set forth in such test an
amount equal to the excess, if any, of the number of STB of Proved Reserves
added to Current Reserves prior to December 31, 2000 over 300,000,000 STB
of Proved Reserves while test (ii) sets a level of only 100,000,000 STB of
Proved Reserves that must be added to Current Reserves during the period
set forth in such test, but does not allow a credit for additions of STB of
Proved Reserves accrued prior to December 31, 2000.
(i) If, between January 1, 2001 and December 31, 2005, an additional
400,000,000 STB of Proved Reserves (that is, 400,000,000 STB of
Proved Reserves in addition to the 100,000,000 STB of Proved
Reserves that are referred to in (a) and the 200,000,000 STB of
Proved Reserves that are referred to in (b)) have not been added
to Current Reserves, then for the year 2006 and each year
thereafter Chargeable Costs as set forth in the table above shall
be reduced, as of January 1 of each such year, by an amount equal
to the lesser of (A) $1.20 or (B) the product of $1.20 and a
fraction, the numerator of which shall be the difference between
(1) 400,000,000 STB of Proved Reserves and (2) the sum of (x) the
actual number of STB of Proved Reserves so added to Current
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Reserves from January 1, 2001 through December 31, 2010 plus (y)
the excess, if any, of the number of STB of Proved Reserves so
added to Current Reserves from January 1, 1988 through December
31, 2000 over 300,000,000 STB of Proved Reserves (provided that
the sum of (x) and (y) shall not exceed 400,000,000 STB of Proved
Reserves) and the denominator of which shall be 400,000,000 STB
of Proved Reserves.
(ii) If, between January 1, 2001 and December 31, 2005, an additional
100,000,000 STB of Proved Reserves (that is, 100,000,000 STB of
Proved Reserves in addition to any and all STB of Proved Reserves
that are added to Current Reserves prior to January 1, 2001) have
not been added to Current Reserves, then for the year 2006 and
each year thereafter, Chargeable Costs as set forth in the table
above shall be reduced, as of January 1 of each such year, by an
amount equal to the lesser of (A) $1.20 or (B) the product of
$1.20 and a fraction, the numerator of which shall be the
difference between 100,000,000 STB of Proved Reserves and the
number of STB of Proved Reserves added to Current Reserves from
January 1, 2001 through December 31, 2005 and the denominator of
which shall be 100,000,000 STB of Proved Reserves.
COST ADJUSTMENT FACTOR
The "Cost Adjustment Factor" is the ratio of (1) the Consumer Price
Index ("CPI") 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); provided, however, that (a) if for any calendar quarter the
average WTI Price is $18.00 or less, then in such event the Cost Adjustment
Factor for such quarter shall 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, shall 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 shall 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 shall 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 by such
Bureau.
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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. For this purpose, such taxes will
be computed at defined statutory rates. In the case of taxes based upon
wellhead or field value, the Overriding 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") and
the Alaska Oil and Gas Conservation Tax ("Alaska Conservation Tax"). For
the purposes of the Royalty Interest, the Alaska Production Tax will be
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 such terms are used with respect to such tax. As of the date of this
report, the statutory rate for the purpose of calculating the "percentage
of value amount" is 15%, and the Alaska Conservation Tax is a tax of $0.004
per barrel of net production. A surcharge to the Alaska Production Tax
increased Production Taxes by $0.05 per barrel of net production effective
July 1, 1989.
ROYALTY PRODUCTION
The Royalty Production for each day in a calendar quarter will be
16.4246% of the first 90,000 barrels of the average of the Company's actual
daily net production of oil and condensate for such quarter as produced
from the company's oil rim and gas cap participation 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 Royalty Production will be based upon oil produced from the
oil rim and condensate produced from the gas cap, but not upon gas
production or natural gas liquids production. The Company's actual average
daily net production of oil and condensate for any calendar quarter will be
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.
CALCULATION OF ROYALTY AMOUNT
The Royalty Interest for each calendar quarter is the sum of the
product of each day in such quarter of (i) the Royalty Production and (ii)
the Per Barrel Royalty; provided that the payment under the Royalty
Interest for any calendar quarter will not be (1) less than zero or (2)
more than the aggregate value of the total production of oil and condensate
from the Company's current working interest in the PBU 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.
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MINIMUM ROYALTY
The Royalty Interest provided for a Minimum Per Barrel Royalty for the
period from February 28, 1989 to September 30, 1991 of $8.92 per barrel
(the "Minimum Per Barrel Royalty"); for all periods thereafter there is no
Minimum Per Barrel Royalty.
The "Average Per Barrel Royalty" for each of the first three calendar
quarters of 1991 was the average of the Per Barrel Royalty for each of the
days in such quarter and in the three preceding quarters. During 1989,
1990, and 1991 through and including October 15, 1991, the Trust's
distributions were based on the Average Per Barrel Royalty and not on the
Minimum Per Barrel Royalty.
POTENTIAL CONFLICTS OF INTEREST BETWEEN THE COMPANY AND TRUST
The interests of the Company and the Trust with respect to the PBU
could at times be different. In particular, because the Per Barrel Royalty
will be 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 Trust Unit holders, although the Company will be subject
to the terms of the Prudhoe Bay Unit Operating Agreement.
Holders of Trust Units will have certain voting rights with respect to
the administration of the Trust, but will have no voting rights with
respect to, and no control over, any operating matters related to the PBU.
The Company will retain the sole right to control all matters relating to
its working interest in the PBU, subject to the terms of the Prudhoe Bay
Unit Operating Agreement.
DESCRIPTION OF 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 pursuant to Article XI of the Trust
Agreement, 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, without
limitation, the obligation to make payments as indemnification), including,
without limitation, contributing to the Company such funds as are necessary
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to make such payments. BP's obligations under the Support Agreement are
unconditional and directly enforceable by Trust 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 PBU, 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 PBU if the transferee is of Equivalent Financial
Standing and unconditionally agrees to assume and be bound by BP's
obligation under the Support Agreement in a writing in form and substance
reasonably satisfactory to the Trustee. A transferee of "Equivalent
Financial Standing" is defined in the Support Agreement as an entity having
a rating assigned to outstanding unsecured, unsupported long term debt from
Moody's Investors Service of at least A3 or from Standard & Poor's
Corporation 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 PBU 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).
DESCRIPTION OF THE PROPERTY
BACKGROUND
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 and during
1989, 1990, 1991, 1992 and 1993, produced on average 1.4 million, 1.3
million, 1.3 million, 1.2 million and 1.1 million barrels of oil and
condensate per day, respectively. The Field is the largest producing field
in North America. As of January 1, 1994, approximately 8.30 billion STB of
oil and condensate had been produced from the Field. The Company estimates
that production will decline at an average rate of approximately 10% per
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year. Field development is well advanced with approximately $16 billion
gross capital spent and a total of about 1,200 wells drilled. Other large
fields located in the same area include the Kuparuk, Endicott, and Lisburne
fields. Production from those fields is not included in the Royalty
Interest.
Since several oil companies hold acreage within the Field, the PBU was
established to optimize Field development. The Prudhoe Bay Unit Operating
Agreement specifies the allocation of production and costs to PBU owners.
The Company and a subsidiary of the Atlantic Richfield Company ("Arco") are
the two Field operators. Other Field owners include affiliates of Exxon
Corporation ("Exxon"), Mobil Corporation ("Mobil"), Phillips Petroleum
Company ("Phillips") and Chevron Corporation ("Chevron").
GEOLOGY
The principal hydrocarbon accumulations at Prudhoe Bay are in the
Ivishak sandstone of the Sadlerochit Group at a depth of approximately
8,700 feet below sea level. The Ivishak is overlain by four minor
reservoirs of varying extent which are designated the Put River, Eileen,
Sag River and Shublik (collectively, "PESS") formations. Underlying the
Sadlerochit Group are the oil-bearing Lisburne and Endicott formations.
The net production referred to herein pertains only to the Ivishak and PESS
formations, collectively known as the Prudhoe Bay (PermoTriassic)
Reservoir, and does not pertain to the Lisburne and Endicott formations.
The Ivishak sandstone was deposited some 250 million years ago during
the Permian and Triassic geologic ages. The sediments in the Ivishak are
composed of sandstones, conglomerate and shales which were deposited by a
massive braided river/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/tar overlays the oil-water
contact in the main field and has an average thickness of around 40 feet.
HYDROCARBONS IN PLACE
The reservoir contained approximately 22 billion STB of original oil
in place, of which approximately 19 billion STB were in the light oil
column. The light oil in the reservoir is a medium grade, low sulfur crude
with an average specific gravity of 27 degrees API.
Original gas in place was approximately 46 trillion standard cubic
feet ("TSCF") (equivalent to approximately 8 billion barrels of oil on a
BTU basis), with 30 TSCF in the gas cap and 16 TSCF solution gas. The gas
cap gas has an average specific gravity of 0.85 and is composed of 70 to
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80% methane, 10 to 20% carbon dioxide and the remainder ethane and heavier
components. The gas cap composition is such that, upon surfacing, a liquid
hydrocarbon phase, known as condensate, is formed.
The interests of the Trust Unit holders are based upon oil produced
from the oil rim and condensate produced from the gas cap, but not upon gas
production (which is currently uneconomic) or natural gas liquids
production stripped from gas produced.
PRUDHOE BAY UNIT OPERATION AND OWNERSHIP
Since several companies hold acreage within the Field's limits, a unit
was established to ensure optimum development of the Field. The Prudhoe
Bay Unit, which became effective on April 1, 1977, divided the Field into
two operating areas. The Company is the operator of the Western Operating
Area ("WOA") and Arco Alaska Inc. is the operator of the Eastern Operating
Area ("EOA"). Oil and condensate production comes from both the WOA and
EOA.
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 Prudhoe Bay Unit ownership by participating area is summarized in
the following table:
<TABLE>
PRUDHOE BAY UNIT
OWNERSHIP BY PARTICIPATING AREA
(AS OF JANUARY 1, 1994)
<CAPTION>
OIL RIM GAS CAP
------- -------
<S> <C> <C>
BP ........................................ 50.68% 13.84%
Arco ...................................... 21.78 42.56
Exxon ..................................... 21.78 42.56
Mobil/Philips/Chevron ("MPC") .............. 4.44 1.04
Others ..................................... 1.32 0.00
------- -------
Total 100.00% 100.00%
------- -------
</TABLE>
OIL RIM REDETERMINATION
The Prudhoe Bay Unit Operating Agreement, which was entered into in
1977, required a final redetermination of participating interests in the
22
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oil rim, based upon improved technical knowledge of the reservoir as a
result of Field operations. In 1982, the Company, Arco and Exxon (the
three major interest owners holding a total of approximately 94% of the oil
rim) reached an agreement regarding final redetermination of participating
interests in the Field.
In October 1982, Exxon initiated arbitration proceedings regarding
final redetermination of participating interests in the oil rim. As a
result of the arbitration proceedings, which were concluded in 1985, the
Company's participating interest in the oil reservoir was 50.68%. At the
current maximum allowable production rate, this resulted in the Company's
interest becoming 655,200 net barrels of oil per day ("BOPD"). Also to
adjust its share of cumulative total production since the inception of
commercial production, the Company overlifted about 13,500 net BOPD for a
two-year period ending in August, 1987. After the arbitration award, MPC
challenged the award through litigation. Mobil, Phillips and Chevron
agreed in principle in October 1990 to end their challenge to the 1985
arbitration on their participating area interest in exchange for a cash
settlement from BP, ARCO and Exxon. This settlement became effective on
completion of a definitive binding agreement between all PBU owners, known
as the Issues Resolution Agreement ("IRA").
The Company has advised the Trustee that the IRA addresses, among
other things, final determination of the Original Condensate Reserve
("OCR"), agreement on allocation of the OCR over time, agreement on an
additional gas handling expansion project (GHX-2), extension of an existing
Enhanced Oil Recovery ("EOR") project to the end of field life and the
establishment of a plan of additional development.
The IRA is an agreement among the owners of the Prudhoe Bay Unit which
is designed to promote cooperation, reduce conflicts, increase efficiency
of operations, and resolve a number of issues that were previously subject
to negotiation, arbitration, or litigation among the Unit owners. The
Company has advised that final approval of the IRA has now been obtained
from all Unit owners.
The Company has further advised that the OCR was finally determined to
be 1,175 million stock tank barrels ("STB") for the Prudhoe Bay Unit, and
that this OCR determination resulted in a reallocation of approximately 500
million STB of crude oil reserves to condensate reserves, for the Prudhoe
Bay Unit. The Company has also advised that because BP owns 50.68% of the
crude oil and 13.84% of the condensate, this OCR settlement alone results
in a BP net reserve reduction. The Company has advised the Trustee,
however, that the establishment of the OCR at this level when combined with
the other elements of the agreement described above should result in no
significant change to BP's net reserves, and that the changes agreed to by
the Prudhoe Bay Unit owners, including the attendant increased production,
are expected to have limited impact on the point at which the company's net
production of oil and condensate would fall below 90,000 barrels per day.
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PRODUCTION AND RESERVES
Production began on June 19, 1977, with the completion of the Trans
Alaska Pipeline System ("TAPS"). Initially 750,000 BOPD was the TAPS
limit, but after start-up, pipeline capacity was increased and in November
1979 a production rate of 1.5 million BOPD was achieved.
As of January 1, 1994, there were about 969 producing oil wells, 35
gas reinjection wells, 57 water injection wells and 100 water and miscible
gas injection wells in the Field, In terms of individual well performance,
oil production rates range from 100 to 8,000 BOPD. Currently, the average
well production rate is about 1,000 BOPD.
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 Company's 1993 share of oil and
condensate (net of State of Alaska royalty) was as follows:
<TABLE>
PRUDHOE BAY UNIT
1993 PRODUCTION
(BARRELS PER DAY)
<CAPTION>
Company Net
Field Share
--------- -------
<S> <C> <C>
Oil ................................ 906,788 400,000
Condensate ......................... 150,049 17,700
Total .............................. 1,056,837 417,700
</TABLE>
The Company's net proved remaining reserves of oil and condensate in
the PBU as of December 31, 1993 were 1,452,900,000 STB. 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. The Company anticipates that its net production from its
current proved reserves will exceed 90,000 barrels per day until the year
2010. The Company also projects continued economic production thereafter,
at a declining rate, until the year 2030; however, for the economic
conditions and reserve estimates as of December 31, 1993 the Per Barrel
Royalty will be zero following the year 2001. Unless 700 million STB are
added to proved reserves from the inception of the Trust to year-end 2005
and 100 million STB of reserves are added between 2001 and 2005, Chargeable
Costs will be reduced beyond 2005 (see CHARGEABLE COSTS). The Company has
added and anticipates adding to its proved reserves. The WTI Price was
24
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$14.15 per barrel on December 31, 1993 compared to $19.50 per barrel on
December 31, 1992. Based on the higher oil price and the gross reserves
projections made for the reservoir as of December 31, 1992, royalty
payments to the Trust were then calculated to continue through the year
2010, or nine years longer than the date calculated using the oil price and
gross reserves projections as of December 31, 1993. The Company estimates
that, if prices and costs had not changed from year-end 1992 to year-end
1993, royalty payments to the Trust would have been projected to continue
through the year 2010. See Report of Miller and Lents, Ltd., Independent
Petroleum Consultants, below.
25
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MILLER AND LENTS, LTD.
OIL AND GAS CONSULTANTS
TWENTY-SEVENTH FLOOR
1100 LOUISIANA
HOUSTON, TEXAS 77002-5216
Telephone 713 651-9455
Telefax 713 654-9914
Cable "MILLENT"
February 25, 1994
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street 21 W
New York, New York 10286
Re: Estimates of Proved Reserves,
Future Annual Production Rates,
And Future Net Revenues for the
BP Prudhoe Bay Royalty Trust
Gentlemen:
This letter report is a summary of those investigations performed in
accordance with our engagement by you for the purposes 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
annual production rate forecasts of oil and condensate made by BP
Exploration (Alaska), Inc. (the Company) attributable to the BP Prudhoe Bay
Royalty Trust (the Trust) from the Company's net interests in the Prudhoe
Bay (Permo-Triassic) Reservoir (the Reservoir) and of the Company's
calculations of Estimated Future Net Revenues and Present Value of
Estimated Future Net Revenues that result from the Proved Reserves
attributable to the Trust, all as of December 31, 1993.
The estimates and calculations reviewed are summarized in the report
prepared by the Company for the Trust and transmitted with a cover letter
dated February 17, 1994, addressed to Ms. Marie Trimboli of The Bank of New
York and signed by Mr. V. W. Holt. Reviews were also performed of (1) the
Company's procedures for estimating and documenting Proved Reserves, (2)
the Company's estimates of in-place reservoir volumes, (3) the Company's
estimates of recovery factors and production profiles for the various
areas, pay zones, projects, and recovery processes that are included in the
Company's estimates of Proved Reserves, (4) the Company's production
strategy and procedures for implementing that strategy, (5) the sufficiency
of the data available for making estimates of Proved Reserves and
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MILLER AND LENTS, LTD.
production profiles, and (6) pertinent provisions of the Prudhoe Bay Unit
Operating Agreement (PBUOA), the Issues Resolution Agreement (IRA), 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 the Company.
Proved Reserves were estimated by the Company 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 PBUOA.
The Prudhoe Bay Unit is an oil and gas unit situated on the North Slope of
Alaska in which the Company's interests in the Reservoir have been unitized
for the production of oil and gas. The 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 working interest of the Company in the Prudhoe Bay Unit.
The payment amount depends upon the Per Barrel Royalty which in turn
depends upon the West Texas Intermediate Price (WTI 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 solely upon the accuracy and
completeness of information provided by the Company with respect to
pertinent ownership interests and various other historical, accounting,
engineering, and geological data.
As a result of our reviews, based on the foregoing, we conclude that:
1. A large body of basic data and detailed analyses is available and
was used by the Company in making its 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
would be minor. Furthermore, the data and analyses on recovery
factors and future production rates are sufficient to support the
Company's Proved Reserves estimates.
2. The methods and procedures employed by the Company 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.
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MILLER AND LENTS, LTD.
3. Based on our limited independent tests of the Company's
computations of reserves, production flowstreams, and future net
revenues, such computations were performed in accordance with the
methods and procedures described to us by the Company.
4. The estimated net remaining Proved Reserves attributable to the
Trust as of December 31, 1993, of 43.2 million barrels of oil and
condensate are, in the aggregate, reasonable. Of this estimate,
all 43.2 million barrels are Proved Developed Reserves.
5. Utilizing the specified procedures outlined in Securities and
Exchange Commission Regulation S-X Rule 4-10(k)(6), the Company
calculated that as of December 31, 1993, production of the Proved
Reserves will result in Estimated Future Net Revenues of $84
million and Present Value of Estimated Future Net Revenues of $65
million to the Trust. Those estimates are reasonable.
6. The Company's estimate that, as of December 31, 1993, 578.1
million barrels of Proved Reserves have been added to Current
Reserves (before taking into account any production therefrom) is
reasonable. Current Reserves are defined in the Overriding
Royalty Conveyance as the Company's net Proved Reserves as of
December 31, 1987, which were 2,035.6 million barrels. 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 Trust.
7. Based on the Company's current plan of operation and development
and on the existing economic environment, the Company's current
estimate that its net production of Proved Reserves of oil and
condensate from the Reservoir will continue at an average rate
exceeding 90,000 barrels per day until the year 2010 is
reasonable. As long as the Per Barrel Royalty has a positive
value, average daily production attributable to the Trust will
remain constant until the Company's net production falls below
90,000 barrels per day; thereafter, production attributable to
the Trust will decline as the Company's production declines.
However, the Per Barrel Royalty will not have a positive value if
the WTI 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 Trust
will have no value to the Trust and can be considered to be zero
regardless of the Company's net production level.
8. Based on the WTI Price of $14.15 per barrel prevailing at
December 31, 1993, current Production Taxes, and the Chargeable
Costs adjusted as prescribed by the Overriding Royalty
Conveyance, the Company's projection that royalty payments to the
Trust will continue through the year 2001 is reasonable. The
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MILLER AND LENTS, LTD.
Company expects continued economic production from the Reservoir
at a declining rate through the year 2030; however, for the
economic conditions and reserve estimates as of December 31,
1993, the Per Barrel Royalty will be zero following the year
2001. Therefore, no reserves are currently included for the
Trust after that date.
9. Although the Company's estimates of gross ultimate Proved
Reserves for the Reservoir increased from year-end 1992 to year-
end 1993, the projections of Proved Reserves and Estimated Future
Net Revenues attributable to the Trust decreased significantly,
primarily because the WTI Price was $14.15 per barrel on December
31, 1993 compared to $19.50 per barrel on December 31, 1992.
Based on the higher oil price and the gross reserves projections
made for the Reservoir as of December 31, 1992, royalty payments
to the Trust were calculated to continue through the year 2010 or
nine years longer than the date calculated using the oil price
and gross reserves projections as of December 31, 1993. The
estimated reserves, economic life, and future revenues
attributable to the Trust may change significantly in the future,
even if expected Reservoir performance does not change, as a
result of changes in prescribed variables and predetermined
calculations that must be made for the Trust using such
variables.
10. The Company estimates that, if prices and costs had not changed
from year-end 1992 to year-end 1993, (a) Proved Reserves
attributable to the Trust at December 31, 1993, would have been
91.7 million barrels, and (b) royalty payments to the Trust would
have been projected to continue through the year 2010. Those
estimates are reasonable.
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. The Company has continual reservoir management,
surveillance, and planning efforts dedicated to (1) gathering new
information, (2) improving the accuracy of its reserves and production
capacity estimates, (3) recognizing and exploiting new opportunities, (4)
anticipating potential problems and taking corrective actions, and (5)
identifying, selecting, and implementing optimum recovery program and cost
reduction alternatives. Given this significant effort and ever-changing
economic conditions, estimates of reserves and production profiles will
change periodically.
The Company's current estimates of Proved Reserves include only those
projects or development programs which it deems highly certain to be
expanded or implemented, given current economic and regulatory conditions.
Future projects, development programs, or offtake strategies different from
those assumed in the current estimates may change future estimates and
affect actual recoveries. However, because several complementary and
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MILLER AND LENTS, LTD.
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 from the Reservoir will be controlled by
facilities limitations and upsets, well downtime, and the effectiveness of
programs to optimize production and costs. The Company 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
anticipated future decline in gross oil and condensate production capacity.
In making its future production rate forecasts, the Company provided
for normal downtime and planned facilities upsets. Although allowances for
unplanned upsets are also considered in its estimates, the Company's
studies and this review do not provide for any impediments to crude oil
production as a consequence of major disruptions.
In making its projections of future net revenues, the Company assumed
that the conservation surcharge, amounting to $0.05 per barrel of
production, which was imposed by the State of Alaska effective July 1,
1989, will continue indefinitely. The purpose of the surcharge is to
provide funds that might be used by the state for spill containment and
clean-up in the event of future discharges of oil or other hazardous
substances. Provisions for periodic suspension of the surcharge under
certain prescribed circumstances are included in the legislation.
Under current economic conditions, gas from the Alaskan North Slope,
except for minor volumes, cannot be marketed commercially. Oil and
condensate recoveries from the Reservoir are expected to be greater as a
result of continued reinjection of produced gas than if major volumes of
produced gas were being sold. No major gas sale is assumed in the
Company's current estimates. If major gas sales are determined to be
economically viable in the future, the Company estimates that such sales
would not actually commence until eight to ten years after such a
determination. In the event that major gas sales are initiated, ultimate
oil and condensate recoveries may be reduced from the current estimates
unless recovery projects other than those included in the current estimates
are implemented.
Large volumes of natural gas liquids are likely to be produced from
the Reservoir 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 Trust is not entitled to royalty payments from
production or sales of natural gas or of 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
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MILLER AND LENTS, LTD.
generally recognized uncertainties associated with interpretation of
geological, geophysical, and engineering information. Government policies
and market conditions different from those employed 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
presented in this report.
Miller and Lents, Ltd., is an independent oil and gas consulting firm.
None of the principals of this firm have any financial interests in the
Company or its parent or any related companies or in the Trust. Our fee is
not contingent upon the results of our work or report, and we have not
performed other services for the Company or the Trust that would affect our
objectivity.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ R. W. Frazier
-----------------
R. W. Frazier
Vice President
RWF/psh
31
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<PAGE>
Estimates of proved reserves are inherently imprecise and subjective
and are revised over time as additional data becomes available. Such
revisions may often be substantial. Information regarding estimates of
proved reserves attributable to the combined interests of the Company and
the Trust were based on Company prepared reserve estimates.
The reserves attributable to the Trust are only a part of the overall
above stated reserves. There is no precise method of allocating estimates
of physical quantities of reserve volumes between the Company and the
Trust, since the Royalty Interest is not a working interest and the Trust
does not own and is not entitled to receive any specific volume of reserves
from the Field. Reserve volumes attributable to the Trust were estimated
by allocating to the Trust its share of estimated future production from
the Field, based on the WTI Prices on December 31, 1993 ($14.15 per
barrel), December 31, 1992 ($19.50 per barrel), December 31, 1991 ($19.10
per barrel), and December 31, 1990 ($28.45 per barrel). Because the
reserve volumes attributable to the Trust are estimated using an allocation
of reserve volumes based on estimated future production, the current WTI
Price, no future movement in the CPI, and no future additions by the
Company of Proved Reserves to Current Reserves, a change in the timing of
estimated production, a change in the WTI Price, future movement in the
CPI, or future additions by the Company of Proved Reserves to Current
Reserves will result in a change in the Trust's estimated reserve volumes.
Therefore, the estimated reserve volumes attributable to the Trust will
vary if different production estimates and prices are used. See "Financial
Statements" and the Note 5 thereto.
As set forth in Note 5 to the Financial Statements, estimated net
proved reserves allocable to the Trust as of December 31, 1993, December
31, 1992, and December 31, 1991 were 43,193,000 barrels, 94,306,000
barrels, and 98,141,000 barrels, respectively. The decrease from December
31, 1992 to December 31, 1993, and from December 31, 1991 to December 31,
1992, reflects the excess of production over additions and changes in
timing of production. The decrease from December 31, 1992 to December 31,
1993 also reflects the decrease in the WTI Price from $19.50 per barrel on
December 31, 1992 to $14.15 per barrel on December 31, 1993. Proved
developed reserves allocable to the Trust as of December 31, 1993, December
31, 1992, and December 31, 1991 were 43,193,000 barrels, 79,420,000
barrels, and 86,116,000 barrels, respectively.
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 PBU working
interest owners. However, several such investments which would augment
Prudhoe Bay projects are already in process. These include additional
drilling, waterflood expansions and miscible injection continuation/
expansion projects. Other possible investments could include expanded gas
cycling, miscible/waterflood infill drilling, miscible injection supply
increases to peripheral areas, chemical flooding, heavy oil tar recovery
and development of the smaller reservoirs. While there is no assurance
that the PBU working interest owners will make any such investments, they
32
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<PAGE>
do regularly assess the technical and economic attractiveness of
implementing further projects to increase PBU proved reserves.
As noted above, the Company's reserve estimates and production
assumptions and projections are predicated upon a reasonable estimate of
hydrocarbon allocation between oil and condensate. The Company's share of
Prudhoe Bay production is the sum of 50.68% of the gross oil production and
13.84% of the gross condensate production from the Field. 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 Company's overall share of oil and condensate production
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 the IRA
effective October 4, 1990 the present allocation procedures will be
adjusted in 1995 to generally allocate condensate in a manner which
approximates the anticipated decline in the production of oil until the
agreed condensate reserve of 1.175 billion STB has been allocated to the
Working Interest Owners. The Company believes this is a reasonable
estimate of hydrocarbon allocation between oil and condensate.
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.
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.
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,
waterflooding and miscible gas flooding. Separate yet integrated reservoir
management strategies have been developed for the areas impacted by each of
these recovery processes.
TRANSPORTATION OF PRUDHOE BAY OIL
Production from the Field is carried to Pump Station 1, which is the
starting point for TAPS, through two 34-inch diameter transit lines, one
from each half of the Field. At Pump Station 1, Alyeska Pipeline Service
33
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<PAGE>
Company, the pipeline operator, meters the oil and pumps it south to Valdez
where it is either loaded onto marine tankers or stored temporarily. It
takes the oil about six days to make the trip in the 48-inch diameter
pipeline.
During 1989, analysis of data gathered by newly developed corrosion
monitoring pigs revealed areas of corrosion previously undetected on TAPS.
All of the corrosion found during 1989 was clustered largely in 13.5 miles,
or less than 2%, of the pipeline length.
In 1989, analysis of data gathered by sophisticated corrosion
monitoring pigs identified previously undetected corrosion on TAPS. An
innovative approach enabled an 8.5 mile section of pipe to be replaced in
1991 without disrupting shipments from the terminal to Valdez. In 1992,
instead of being replaced, a two mile section near Chandalar received
specific repairs. This and other developments have cut the cost of repairs
on the main line. Pump station piping corrosion costs have also been
reduced significantly. The State of Alaska filed protests to the 1990,
1991, 1992, 1993 and 1994 TAPS tariffs, seeking to exclude corrosion costs
from the tariffs charged to ship oil through TAPS. The State of Alaska and
the other parties have agreed to continue attempts to resolve the dispute
among themselves. Additional protests were filed by the State of Alaska in
1994 challenging the inclusion of certain public affairs and other expenses
in such tariffs.
34
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HISTORICAL PRODUCTION OF OIL AND CONDENSATE
The following table sets forth information concerning the production
of oil and condensate for the periods indicated. The amounts listed are the
Company's share of production, net of royalties to the State of Alaska.
<TABLE>
HISTORICAL PRODUCTION
<CAPTION>
Year Ended Oil and
December 31, Condensate Produced
(bpd)
<S> <C>
1987 ....................... 687,000(a)
1988 ....................... 652,500
1989 ....................... 587,200
1990 ....................... 540,000
1991 ....................... 530,000
1992 ....................... 481,800
1993 ....................... 417,700
<FN>
(a) Reflects an overlifting of 13,500 barrels per day through August
31, 1987 resulting from the redetermination of the MPC group ownership of
the PBU. See "Oil Rim Redetermination" above.
</TABLE>
INDUSTRY CONDITIONS
The production of oil and gas in Alaska is affected by many state and
federal regulations with respect to allowable rates of production,
marketing, environmental matters and pricing. Future regulations could
change allowable rates of production or the manner in which oil and gas
operations may be lawfully conducted.
In general, the Company's oil and gas activities are subject to laws
and regulations relating to environmental quality and pollution control.
The Company believes that the equipment and facilities currently being used
in its operations generally comply with the applicable legislation and
regulations. During the past few years, numerous environmental laws and
regulations have taken effect at the federal, state and local levels. Oil
and gas operations are subject to extensive federal and state regulation
and to interruption or termination by governmental authorities due to
ecological and other considerations. Although the existence of legislation
and regulation has had no material adverse effect on the Company's current
method of operations, existing and future legislation and regulations could
result in the Company experiencing delays and uncertainties in commencing
projects. The ultimate impact of such legislation and regulations cannot
generally be predicted.
35
<PAGE>
<PAGE>
Oil prices are subject to international supply and demand. Political
developments (especially in the Middle East) and the outcome of meetings of
OPEC can particularly affect world oil supply and oil prices.
CERTAIN TAX CONSIDERATIONS
The following is a summary of the principal tax consequences to the
Trust Unit holders resulting from the ownership and disposition of Trust
Units. The laws or regulations affecting these matters are subject to
change by future legislation or regulations or new interpretations by the
IRS, state taxing authorities or the courts, which could adversely affect
Trust Unit holders. In addition, there may be differences of opinion as to
the applicability or interpretation of present tax laws or regulations. BP
and the Trust have not requested from the IRS any rulings on the tax
treatment described below, and no assurance can be given that such tax
treatment will be available.
Taxpayers are urged to consult their tax advisors on the application
of the following discussion to their specific circumstances.
EMPLOYEES
The Trust has no employees. Administrative functions of the Trust are
performed by the Trustee.
FEDERAL INCOME TAX
CLASSIFICATION OF THE TRUST
The Trust files its federal tax return as a "grantor trust" rather
than as "an association taxable as a corporation." If the Trust were
determined to be an association taxable as a corporation, it would be
treated as an entity taxable as a corporation on the taxable income from
the Royalty Interest, the Trust Unit holders would be treated as
shareholders, and distributions to Trust Unit holders would not be
deductible in computing the Trust's tax liability as an association. The
following discussion is based on the legal conclusion that the Trust will
be classified as a grantor trust under current law.
TAXATION OF THE TRUST
A grantor trust is not subject to tax, and its beneficiaries (the
Trust Unit holders in the case of the Trust) are considered for tax
purposes to own its income and corpus. A grantor trust files an
information return reporting all items of income or deduction. The Trust,
therefore, will pay no federal income tax, but will file an information
return.
36
<PAGE>
<PAGE>
TAXATION OF TRUST UNIT HOLDERS
The income of the Trust will be deemed to have been received or
accrued by the Trust Unit holders at the time such income is received or
accrued by the Trust and not when distributed by the Trust. Income will be
recognized by a Trust Unit holder consistent with its method of accounting
and without regard to the accounting period or method employed by the
Trust.
The Trust will make quarterly distributions to Trust Unit holders of
record on each Quarterly Record Date. See "Description of the Trust Units
and the Trust Agreement--Distributions of Income." The terms of the Trust
Agreement as described above, seek to assure to the extent practicable that
taxable income attributable to such distributions will be reported by the
Trust Unit holder who receives such distributions, assuming that such
holder is the owner of record on the Quarterly Record Date. In certain
circumstances, however, a Trust Unit holder may be required to report
taxable income attributable to its Trust Units, but the Trust Unit holder
will not receive the distribution attributable to such income. For
example, if the Trustee establishes a reserve or borrows money to satisfy
debts and liabilities of the Trust income used to establish such reserve or
to repay such loan must be reported by the Trust Unit holder, even though
such income is not distributed to the Trust Unit holder.
The Trust intends to allocate income and deductions to Trust Unit
holders based on record ownership at Quarterly Record Dates. It is unknown
whether the IRS will accept such allocation or will require income and
deductions of the Trust to be determined and allocated daily or require
some method of daily proration, which could result in an increase in the
administrative expenses of the Trust.
It is anticipated that each Trust Unit holder will be entitled to a
deduction for cost depletion and certain other deductions for state and
local taxes imposed upon the Trust or a Trust Unit holder and
administrative expenses of the Trust. A Trust Unit holder's deduction for
cost depletion in any year will be calculated by multiplying the holder's
adjusted tax basis in the Trust Units (generally its 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. Trust Unit holders
acquiring units on or after October 12, 1990 are possibly permitted to
utilize percentage depletion with respect to such Units. Percentage
depletion is based on the Trust Unit holders 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 Trust Unit holder will
reduce its adjusted basis in its Trust Units for purposes of computing
subsequent depletion or gain or loss on any subsequent disposition of Trust
Units.
37
<PAGE>
<PAGE>
Each Trust Unit holder must maintain records of its adjusted basis in
the Trust Units, make adjustments for depletion deductions to such basis,
and use such basis for the computation of gain or loss on the disposition
of the Trust Units.
TAXATION OF NONRESIDENT ALIEN INDIVIDUALS, PARTNERSHIPS AND FOREIGN
CORPORATIONS
Generally, nonresident alien individuals, partnerships and foreign
corporations (i.e., Foreign persons) are subject to a tax of 30 percent on
gross income from sources within the U.S. that are not from a U.S. trade or
business. Income from the Trust is considered income which is not
effectively connected with a U.S. trade or business. As a result, Foreign
persons would be subject to a 30 percent tax on their gross income from the
Trust, without deductions. Usually such tax is to be withheld at the
source of payment by the withholding agent. However, if there is a treaty
in effect between the U.S. and the country of residence of the foreign
person, such treaty may reduce the rate of withholding.
A holder of Trust Units who is a Foreign person may make an election
pursuant to Internal Revenue Code Section 871 (d) or 882(d), or pursuant to
any similar provisions of applicable treaties, to treat the income (which
constitutes income from real property) from the Trust as income which is
effectively connected with a U.S. trade or business. If this election is
made such a holder of Trust Units will not be subject of withholding but
will, however, be taxed on such income in the same manner as a U.S. person
(i.e. U.S. individual, partnership or corporation). As a result, such
holder of Trust Units will be taxed on his net income as opposed to his
gross income from the Trust. Also, under such an election, any gain or
loss upon the disposition of a Trust Unit will be deemed to be connected
with a U.S. trade or business and taxed in the manner described above. If
a Foreign person owns a greater than 5 percent interest in the Trust, that
interest is a U.S. real property interest as provided under Internal
Revenue Code Section 897. Gain on disposition of that interest will be
taxed as if the holder of Trust Units were a U.S. person. In addition,
Foreign persons subject to Internal Revenue Code Section 897 who are
nonresident alien individuals will be subject to a minimum tax of 21
percent on the lesser of:
1. the individual's alternative minimum taxable income for the taxable
year, or
2. the net gain from the disposal of the Trust Unit.
Gain or loss on the disposition is determined by subtracting the
adjusted basis of the Trust Units from the proceeds received. If the
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
38
<PAGE>
<PAGE>
effectively connected income. The branch profits tax may be either reduced
or eliminated by treaty.
SALE OF TRUST UNITS
Generally, a Trust Unit holder will realize gain or loss on the sale
or exchange of his Trust Units measured by the difference between the
amount realized on the sale or exchange and his adjusted basis for such
Trust Units. Gain on the sale of Trust Units by a holder that is not a
dealer with respect to such Trust Units will be treated as ordinary income
to the extent of any depletion deductions taken by such holder and the
balance, if any, of the gain will be treated as capital gain.
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. A Unit holder
will avoid backup withholding by furnishing his correct TIN to the Trustee
in the form required by law.
REPORTS
The Trustee will furnish the Trust Unit holders of record quarterly
and annual reports described above under "Description of the Trust Units
and the Trust Agreement-Reports to Holders of Trust Units" in order to
permit computation of tax liability by the Trust Unit holders.
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. Corporate Unit holders should be advised that all
Trust income is Alaska source income and should be reported accordingly.
ITEM 2. PROPERTIES
Reference is made to "Item I.- Business" for the information
required by this item.
ITEM 3. LEGAL PROCEEDINGS
Not applicable.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS
Not applicable.
39
<PAGE>
<PAGE>
PART II
ITEM 5. MARKET FOR TRUST UNITS
<TABLE>
The Trust Units are listed on the New York Stock Exchange ("NYSE").
The following table represents the high and low per unit sales prices for
the Trust Units as reported on the consolidated tape for 1992 and 1993 and
the distributions paid by the Trust for the periods presented.
<CAPTION>
Distributions Per
Trust Unit
----------
High Low 1992 1993
1992 1993 1992 1993 _____ _____
<S> <C> <C> <C> <C> <C> <C>
First Quarter $31.250 $31.750 $27.875 $29.500 0.619 0.590
Second Quarter $31.125 $31.625 $29.500 $27.750 0.744 0.595
Third Quarter $31.250 $29.625 $29.375 $26.125 0.775 0.499
Fourth Quarter $31.875 $29.625 $30.250 $23.875 0.707 0.424
</TABLE>
As of March 18, 1994, there were 2,181 registered holders of Trust
Units.
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 PBU.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to "Item 1. - Report of Miller and Lents, Ltd.,
Independent Petroleum Consultants" of this Annual Report on Form 10-K.
40
<PAGE>
<PAGE>
The following table presents in summary form selected financial
information regarding the Trust.
<TABLE>
BP PRUDHOE BAY ROYALTY TRUST
Statements of Cash Earnings and Distributions
For each of the years in the four-year period ended
December 31, 1993, 1992, 1991 and 1990 and
for the period of February 28, 1989 (date of formation)
to December 31, 1989
(In thousands, except unit data)
<CAPTION>
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Royalty revenues $ 51,727 65,250 87,010 76,788 40,776
Trust administrative
expenses 554 413 412 457 170
---------- ---------- ---------- ---------- ----------
Cash earnings $ 51,173 64,837 86,598 76,331 40,606
========== ========== ========== ========== ==========
Cash distributions $ 51,173 64,837 86,598 76,331 40,606
========== ========== ========== ========== ==========
Cash distributions
per unit $ 2.391 3.030 4.046 3.567 1.897
========== ========== ========== ========== ==========
Units outstanding 21,400,000 21,400,000 21,400,000 21,400,000 21,400,000
========== ========== ========== ========== ==========
</TABLE>
ITEM 1. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION
The Trust is a passive entity with the Trustee having only such powers
as are necessary for the collection and distribution of revenues from the
Royalty Interest, the payment of Trust liabilities and expenses and the
protection of the Royalty Interest. All royalty payments received by the
Trustee are distributed, net of Trust expenses, to Trust Unit holders.
Accordingly, a discussion of liquidity or capital resources is not
applicable.
41
<PAGE>
<PAGE>
RESULTS OF OPERATIONS
Payments to the Trust with respect to the Royalty Interest are
generally payable on the fifteenth day after the end of the calendar
quarter (or the next succeeding business day if such fifteenth day is not a
business day) in an amount equal to the per barrel WTI Price for each day
during the calendar quarter less the sum of (i) the product of the per
barrel Chargeable Costs and the Cost Adjustment Factor (such product
hereinafter referred to as "Adjusted Chargeable Costs") and (ii) the per
barrel Production Taxes, multiplied by the Royalty Production.
42
<PAGE>
<PAGE>
ACTUAL RESULTS
During 1993 the Trust received payments with respect to the Royalty
Interest in the aggregate amount of $51,727,000 and made distributions to
Unit holders in the aggregate amount of $51,173,000. The payment with
respect to the Royalty Interest for the calendar quarter ended December 31,
1993, which was paid to the Trust on January 18, 1994, was $9,172,000. The
following table sets forth with respect to each calendar quarter the
average WTI price, the per barrel Chargeable Costs, the Cost Adjustment
Factor, the per barrel Adjusted Chargeable Costs, the per barrel Production
Taxes, and the Per Barrel Royalty.
<TABLE>
<CAPTION>
CALENDAR YEARS 1993, 1992, AND 1991
1/1-3/31 4/1-6/30 7/1-9/30 10/1-12/31
-------- -------- -------- ----------
1993 1992 1991 1993 1992 1991 1993 1992 1991 1993 1992 1991
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Average WTI
Price $19.85 $18.94 $21.68 $19.76 $21.20 $20.79 $17.77 $21.67 $21.66 $16.43 $20.50 $21.73
Chargeable
Costs 6.75 6.00 4.50 6.75 6.00 4.50 6.75 6.00 4.50 6.75 6.00 4.50
Cost
Adjustment
Factor 1.171 1.134 1.103 1.180 1.143 1.109 1.180 1.153 1.118 1.180 1.162 1.127
Adjusted
Chargeable
Costs 7.90 6.80 4.96 7.96 6.86 4.99 7.96 6.92 5.03 7.96 6.97 5.07
Production
Taxes 2.24 2.13 2.56 2.22 2.46 2.42 1.92 2.53 2.55 1.72 2.34 2.55
Per Barrel
Royalty 9.71 10.00 14.16 9.57 11.88 13.37 7.88 12.23 14.08 6.74 11.18 14.11
<FN>
(All Figures after rounding)
</TABLE>
43
<PAGE>
<PAGE>
As discussed above in Part I "Industry Conditions" the production of
oil and gas in Alaska is affected by many state and federal regulations.
Existing and future legislation and regulations could result in the
Company's experiencing delays and uncertainties, although the ultimate
impact cannot generally be predicted. Per barrel royalty payments will
also remain subject to oil prices, to the WTI Price, to Chargeable Costs,
which increase in accordance with the schedule contained above under
"Description of the Royalty Interest-Chargeable Costs", to the Cost
Adjustment Factor, which is based on CPI, and to Production Taxes which
increased by $.05 effective July 1, 1989.
44
<PAGE>
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
BP PRUDHOE BAY ROYALTY TRUST
INDEX TO FINANCIAL STATEMENTS
Page
Independent Auditors' Report ................................. 46
Statements of Assets, Liabilities and Trust Corpus
as of December 31, 1993 and 1992.............................. 47
Statements of Cash Earnings and Distributions for
the years ended December 31, 1993, 1992 and 1991.............. 48
Statements of Changes in Trust Corpus for the years
ended December 31,1993, 1992 and 1991......................... 49
Notes to Financial Statements................................. 50
45
<PAGE>
<PAGE>
INDEPENDENT AUDITORS' REPORT
----------------------------
Trustee and Holders of Trust Units of
BP Prudhoe Bay Royalty Trust:
We have audited the accompanying statements of assets, liabilities and
Trust Corpus of BP Prudhoe Bay Royalty Trust as of December 31, 1993 and
1992, and the related statements of cash earnings and distributions and
changes in Trust Corpus for each of the years in the three-year period
ended December 31, 1993. These financial statements are the responsibility
of the Trustee. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by the Trustee, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
As described in note 2 to the financial statements, these financial
statements have been prepared on a modified basis of cash receipts and
disbursements, which is a comprehensive basis of accounting other than
generally accepted accounting principles.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the assets, liabilities and Trust Corpus
of BP Prudhoe Bay Royalty Trust as of December 31, 1993 and 1992, and its
cash earnings and distributions and its changes in Trust Corpus for each of
the years in the three-year period ended December 31, 1993 on the basis of
accounting described in note 2.
KPMG Peat Marwick
New York, New York
March 14, 1994
46
<PAGE>
<PAGE>
<TABLE>
BP PRUDHOE BAY ROYALTY TRUST
Statements of Assets, Liabilities and Trust Corpus
December 31, 1993 and 1992
(In thousands, except unit data)
<CAPTION>
ASSETS 1993 1992
---- ----
<S> <C> <C>
Royalty interest (notes 1 and 2) $ 535,000 535,000
Less: accumulated amortization (127,859) (97,250)
---------- ----------
Total assets $ 407,141 437,750
========== ==========
LIABILITIES AND TRUST CORPUS
Accrued expenses $ 84 84
Trust Corpus (40,000,000 units
of beneficial interest
authorized, 21,400,000 units
issued and outstanding) 407,057 437,666
Contingencies (note 3) __________ __________
Total liabilities and Trust Corpus $ 407,141 437,750
========== ==========
<FN>
See accompanying notes to financial statements.
</TABLE>
47
<PAGE>
<PAGE>
<TABLE>
BP PRUDHOE BAY ROYALTY TRUST
Statements of Cash Earnings and Distributions
For the Years Ended December 31, 1993, 1992 and 1991
(In thousands, except unit data)
<CAPTION>
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Royalty revenues $ 51,727 65,250 87,010
Trust administrative expenses 554 413 412
---------- ---------- ----------
Cash earnings $ 51,173 64,837 86,598
========== ========== ==========
Cash distributions $ 51,173 64,837 86,598
========== ========== ==========
Cash distributions per unit $ 2.391 3.030 4.046
========== ========== ==========
Units outstanding 21,400,000 21,400,000 21,400,000
========== ========== ==========
<FN>
See accompanying notes to financial statements.
</TABLE>
48
<PAGE>
<PAGE>
<TABLE>
BP PRUDHOE BAY ROYALTY TRUST
Statements of Changes in Trust Corpus
For the Years Ended December 31, 1993, 1992 and 1991
(In thousands)
<CAPTION>
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Trust Corpus at beginning of year $ 437,666 467,158 490,929
Cash earnings 51,173 64,837 86,598
Decrease (increase) in
accrued Trust expenses - 1 (10)
Cash distributions (51,173) (64,837) (86,598)
Amortization of Royalty Interest (30,609) (29,493) (23,761)
--------- --------- ---------
Trust corpus at end of year $ 407,057 437,666 467,158
========= ========= =========
<FN>
See accompanying notes to financial statements.
</TABLE>
49
<PAGE>
<PAGE>
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
December 31, 1993, 1992 and 1991
(1) FORMATION OF THE TRUST AND ORGANIZATION
BP Prudhoe Bay Royalty Trust (the "Trust") was formed pursuant to a
Trust Agreement dated February 28, 1989 among The Standard Oil Company
("Standard Oil"), BP Exploration (Alaska) Inc. (the "Company"), The
Bank of New York and a co-trustee (collectively, the "Trustee").
Standard Oil and the Company are indirect wholly owned subsidiaries of
the British Petroleum Company p.l.c. ("BP").
On February 28, 1989, Standard Oil conveyed a royalty interest
(the "Royalty Interest") to the Trust. The Trust was formed for the
sole purpose of owning and administering the Royalty Interest. The
Royalty Interest represents the right to receive, effective February
28, 1989, a per barrel royalty (the "Per Barrel Royalty") on 16.4246%
of the lesser of (a) the first 90,000 barrels of the average actual
daily net production of oil and condensate per quarter or (b) the
average actual daily net production of oil and condensate per quarter
from the Company's working interest in the Prudhoe Bay Field (the
"Field") located on the North Slope of Alaska. Trust Unit holders
will remain subject at all times to the risk that production will be
interrupted or discontinued or fall, on average, below 90,000 barrels
per day in any quarter. BP has guaranteed the performance by the
Company of its payment obligations with respect to the Royalty
Interest.
The co-trustees of the Trust are The Bank of New York, a New York
corporation authorized to do a banking business, and The Bank of New
York (Delaware), a Delaware banking corporation. The Bank of New York
(Delaware) serves as co-trustee in order to satisfy certain
requirements of the Delaware Trust Act. The Bank of New York alone is
able to exercise the rights and powers granted to the Trustee in the
Trust Agreement.
The Per Barrel Royalty in effect for any day is equal to the
price of West Texas Intermediate crude oil (the "WTI Price") for that
day less scheduled Chargeable Costs (adjusted in certain situations
for inflation) and Production Taxes (based on statutory rates then in
existence). During the period from February 28, 1989 (date of
formation) to September 30, 1991, the Royalty Interest provided for a
minimum royalty in certain situations. For years subsequent to 1995,
Chargeable Costs will be reduced up to a maximum amount of $1.20 per
barrel in each year if additions to the Field's proved reserved from
January 1, 1988 do not meet certain specific levels.
The Trust is passive, with the Trustee having only such powers as
are necessary for the collection and distribution of revenues, the
payment of Trust liabilities and the protection of the Royalty
(Continued)
- 50 -
<PAGE>
<PAGE>
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
Interest. The Trustee is obligated to establish cash reserves and,
subject to certain conditions, is obligated to borrow funds to pay
liabilities of the Trust when they become due. The Trustee may sell
Trust properties only (a) as authorized by a vote of the Trust Unit
holders, (b) when necessary to provide for the payment of specific
liabilities of the Trust then due (subject to certain conditions) or
(c) upon termination of the Trust. Each Trust Unit issued and
outstanding represents an equal undivided share of beneficial interest
in the Trust. Royalty payments are received by the Trust and
distributed to Trust Unit holders, net of Trust expenses, in the month
succeeding the end of each calendar quarter. The Trust will terminate
upon the first to occur of the following events:
(a) On or prior to December 31, 2010: upon a vote of Trust Unit
holders of not less than 70% of the outstanding Trust Units.
(b) After December 31, 2010: (i) upon a vote of Trust Unit
holders of not less than 60% of the outstanding Trust Units,
or (ii) at such time the net revenues from the Royalty
Interest for two successive years commencing after 2010 are
less than $1,000,000 per year (unless the net revenues
during such period are materially and adversely affected by
certain events).
(2) BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on a modified cash
basis and reflect the Trust's assets, liabilities and Trust Corpus and
the earnings and distributions as follows:
(a) Revenues are recorded when received (generally within 15
days of the end of the preceding quarter) and distributions
to Trust Unit holders are recorded when paid.
(b) Trust expenses (which include accounting, engineering,
legal, and other professional fees, trustees' fees and out-
of-pocket expenses) are recorded when incurred.
(c) Amortization of the Royalty Interest is calculated based on
the units-of-production attributable to the Trust over the
production of estimated proved reserves attributable to the
Trust at the beginning of the fiscal year (approximately
94,306,000, 98,141,000 and 121,500,000 barrels,
respectively, were used to calculate the amortization of the
Royalty Interest for the years ended December 31, 1993, 1992
and 1991, respectively), is charged directly to the Trust
Corpus, and does not affect cash earnings. The rate for
amortization per net equivalent barrel of oil was $5.67,
$5.45 and $4.40 for the years ended December 31, 1993, 1992
and 1991, respectively. The remaining unamortized balance
of the net overriding Royalty Interest at December 31, 1993
(Continued)
- 51 -
<PAGE>
<PAGE>
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
is not necessarily indicative of the fair market value of
the interest held by the Trust.
While these statements differ from financial statements prepared
in accordance with generally accepted accounting principles, the cash
basis of reporting revenues and distributions is considered to be the
most meaningful because quarterly distributions to the Unit holders
are based on net cash receipts. The accompanying modified cash basis
financial statements contain all adjustments necessary to present
fairly the assets, liabilities and Trust Corpus of the Trust as of
December 31, 1993 and 1992 and its cash earnings and distributions and
changes in Trust Corpus for each of the years in the three-year period
ended December 31, 1993.
The conveyance of the Royalty Interest by Standard Oil to the
Trust was accounted for as a purchase transaction. On February 28,
1989, Standard Oil sold 13,360,000 Trust Units to a group of
institutional investors for $334 million in a private placement. For
financial reporting purposes, the Trust's management valued the
remaining Trust Units owned by Standard Oil (8,040,000 units) at a per
unit value equivalent to the amount paid by the investors in the
private placement.
(3) INCOME TAXES
The Trust files its federal tax return as a grantor trust subject
to the provisions of subpart E of Part I of Subchapter J of the
Internal Revenue Code of 1986, as amended, rather than an association
taxable as a corporation. The Unit holders are treated as the owners
of Trust income and Corpus, and the entire taxable income of the Trust
will be reported by the Unit holders on their respective tax returns.
(Continued)
- 52 -
<PAGE>
<PAGE>
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
If the Trust were determined to be an association taxable as a
corporation, it would be treated as an entity taxable as a corporation
on the taxable income from the Royalty Interest, the Trust Unit
holders would be treated as shareholders, and distributions to Trust
Unit holders would not be deductible in computing the Trust's tax
liability as an association.
(4) SUMMARY OF QUARTERLY RESULTS (UNAUDITED)
<TABLE>
A summary of selected quarterly financial information for the
years ended December 31, 1993 and 1992 is as follows (in thousands,
except unit data):
<CAPTION>
1ST 2ND 3RD 4TH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
<S> <C> <C> <C> <C>
1993
Royalty revenues $ 15,209 12,918 12,878 10,722
Trust administrative expenses 84 286 142 42
------ ------ ------ ------
Cash earnings 15,125 12,632 12,736 10,680
Cash distributions 15,125 12,632 12,736 10,680
Cash distributions per unit 0.707 0.590 0.595 0.499
1992
Royalty revenues $ 19,186 13,456 15,982 16,626
Trust administrative expenses 99 203 60 51
------ ------ ------ ------
Cash earnings 19,087 13,253 15,922 16,575
Cash distributions 19,087 13,253 15,922 16,575
Cash distributions per unit 0.892 0.619 0.744 0.775
</TABLE>
(5) SUPPLEMENTAL RESERVE INFORMATION AND STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOW RELATING TO PROVED RESERVES
(UNAUDITED)
Pursuant to Statement of Financial Accounting Standards No. 69 -
"Disclosures About Oil and Gas Producing Activities" ("FASB 69"), the
Trust is required to include in its financial statements supplementary
information regarding estimates of quantities of proved reserves
attributable to the Trust and future net cash flows.
Estimates of proved reserves are inherently imprecise and
subjective and are revised over time as additional data becomes
available. Such revisions may often be substantial. Information
regarding estimates of proved reserves attributable to the combined
(Continued)
- 53 -
<PAGE>
<PAGE>
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
interests of the Company and the Trust were based on Company-prepared
reserve estimates. The Company's reserve estimates are believed to be
reasonable and consistent with presently known physical data
concerning the size and character of the Field.
There is no precise method of allocating estimates of physical
quantities of reserve volumes between the Company and the Trust, since
the Royalty Interest is not a working interest and the Trust does not
own and is not entitled to receive any specific volume of reserves
from the Field. Reserve volumes attributable to the Trust were
estimated by allocating to the Trust its share of estimated future
production from the Field, based on the WTI Price on December 31, 1993
($14.15 per barrel), December 31, 1992 ($19.50 per barrel) and
December 31, 1991 ($19.10 per barrel). Because the reserve volumes
attributable to the Trust are estimated using an allocation of reserve
volumes based on estimated future production and on the current WTI
Price, a change in the timing of estimated production or a change in
the WTI price will result in a change in the Trust's estimated reserve
volumes. Therefore, the estimated reserve volumes attributable to the
Trust will vary if different production estimates and prices are used.
In addition to production estimates and prices, reserve volumes
attributable to the Trust are affected by the amount of Chargeable
Costs that will be deducted in determining the Per Barrel Royalty.
The Royalty Interest includes a provision under which, in years
subsequent to 1995, if additions to the Field's proved reserves from
January 1, 1988 do not meet certain specified levels, Chargeable Costs
will be reduced up to a maximum amount of $1.20 per barrel in each
year. Under the provisions of FASB 69, no consideration can be given
to reserves not considered proved at the present time. Accordingly,
in estimating the reserve volumes attributable to the Trust,
Chargeable Costs were reduced by the maximum amount in years
subsequent to 1995, after considering the amount of reserves that have
been added to the Field's proved reserves from January 1, 1988.
Net proved reserves of oil and condensate attributable to the
Trust as of December 31, 1993, 1992 and 1991 based on the Company's
latest reserve estimate at such time, the WTI Prices on December 31,
1993, 1992 and 1991 and a reduction in Chargeable Costs in years
subsequent to 1995, were estimated to be 43, 94 and 98 million
barrels, respectively (of which 43, 79 and 86 million barrels,
respectively, are proved developed).
The standardized measure of discounted future net cash flow
relating to proved reserves disclosure required by FASB 69 assigns
monetary amounts to proved reserves based on current prices. This
discounted future net cash flow should not be construed as the current
market value of the Royalty Interest. A market valuation
determination would include, among other things, anticipated price
increases and the value of additional reserves not considered proved
at the present time or reserves that may be produced after the
(Continued)
- 54 -
<PAGE>
<PAGE>
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
currently anticipated end of field life. At December 31, 1993, 1992
and 1991 the standardized measure of discounted future net cash flow
relating to proved reserves attributable to the Trust (estimated in
accordance with the provisions of FASB 69), based on the WTI Prices on
those dates of $14.15, $19.50 and $19.10, respectively, were as
follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1993 1992 1991
----------- ----------- -----------
<S> <C> <C> <C>
Future net cash flows $ 83,735 498,966 561,049
10% annual discount for
estimated timing of
cash flows (18,563) (214,670) (248,425)
-------- -------- --------
Standardized measure of
discounted future net
cash flow relating to
proved reserves (a) $ 65,172 284,296 312,624
======== ======== ========
<FN>
(a) The standardized measure of discounted future net cash flows
relating to proved reserves, estimated without reducing
Chargeable Costs in years subsequent to 1995, would be $65,174,
$228,566, and $282,847 at December 31, 1993, 1992 and 1991,
respectively.
</TABLE>
(Continued)
- 55 -
<PAGE>
<PAGE>
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
The following are the principal sources of the change in the
standardized measure of discounted future net cash flows (in
thousands):
<TABLE>
<CAPTION>
1993 1992 1991
--------- --------- ---------
<S> <C> <C> <C>
Revisions of prior estimates:
Reserve volumes $ 16,747 1,272 10,471
WTI price (245,140) 26,168 (482,419)
Chargeable costs - inflation (8,537) (20,433) (21,563)
Production taxes 37,347 (2,760) 73,130
Other (2,280) (2,564) (5,109)
--------- --------- ---------
(201,863) 1,683 (425,490)
Royalty income received (b) (45,691) (61,273) (75,159)
Accretion of discount 28,430 31,262 73,934
--------- --------- ---------
Net decrease during the year $ (219,124) (28,328) (426,715)
========= ========= =========
<FN>
(b) Royalty income received for 1993, 1992 and 1991 includes the
royalty applicable to the period October 1, 1993 through December
31, 1993 ($9,172), October 1, 1992 through December 31, 1992
($15,209) and October 1, 1991 through December 31, 1991
($19,186), which was received by the Trust in January 1994, 1993
and 1992, respectively.
</TABLE>
(Continued)
- 56 -
<PAGE>
<PAGE>
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
<TABLE>
The changes in quantities of proved oil and condensate were as follows
(thousands of barrels):
<CAPTION>
<S> <C>
Estimated net proved reserves of oil
and condensate at December 31, 1991 98,141
Production (5,410)
Change in timing of estimated production 1,575
-------
Estimated net proved reserves of oil
and condensate at December 31, 1992 94,306
Production (5,395)
Change in timing of estimated production (45,718)
-------
Estimated net proved reserves of oil
and condensate at December 31, 1993 43,193
=======
Proved developed reserves:
December 31, 1991 86,116
=======
December 31, 1992 79,424
=======
December 31, 1993 43,193
=======
</TABLE>
(Continued)
- 57 -
<PAGE>
<PAGE>
ITEM 9. CHANGES IN ACCOUNTANTS
The Trust dismissed Ernst & Whinney as its independent accountants on
June 15, 1989 and, as of the same date, engaged KPMG Peat Marwick as
independent accountants.
A Form F-3 Registration Statement (Registration No. 33-27923) filed by
BP, the Company, and Standard Oil contained a single financial statement of
the Trust audited by Ernst & Whinney, namely, a Statement of Assets and
Trust corpus as of February 28,1989. The report of Ernst & Whinney on the
Statement of Assets and Trust corpus contained in Registration Statement No.
33-27923 did not contain an adverse opinion or disclaimer of opinion and was
not qualified or modified as to uncertainty, audit scope or accounting
principles. During the period from February 28, 1989 through June 15, 1989
there were no disagreements with Ernst & Whinney on any matter of accounting
principles or practices, financial statement disclosure, or auditing scope
or procedure, which disagreements if not resolved to the satisfaction of
Ernst & Whinney would have caused them to make reference thereto in their
report on the Statement of Assets and Trust corpus as of February 28, 1989.
During the period from February 28, 1989 through June 15, 1989, there were
no reportable events (as defined in Regulation S-K Item 304(a)(1)(v)) with
Ernst & Whinney. Ernst & Whinney has furnished the Trust with a copy of a
letter addressed to the Securities and Exchange Commission stating that it
agreed with the above statements.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
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
(a) Unit Ownership of Certain Beneficial Owners.
58
<PAGE>
<PAGE>
As of March 18, 1994 the Trustee does not know of any person
beneficially owning 5% or more of the Trust Units except based on filings
with the Securities and Exchange Commission dated as of December 31, 1993,
which filings set forth the following:
Name No. of Units Percentage
J.P. Morgan & Co., Inc. 2,391,300(1) 11.1
23 Wall Street
New York, N.Y. 10007
Prudential Insurance Company
of America 3,001,600(1) 14
3 Gateway Center
Newark, N.J. 07102
(1) Amount known to be Units with respect to which beneficial owner has the
right to acquire beneficial ownership: None.
(b) Unit Ownerships of Management
Neither the Company, Standard Oil, nor BP owns any Units. Neither The
Bank of New York, as Trustee, or in its individual capacity, nor The Bank of
New York (Delaware), as co-trustee, or in its individual capacity, owns any
Units.
(c) Change 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.
59
<PAGE>
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) FINANCIAL STATEMENTS
The following financial statements of the Trust are included in Part
II, Item 8:
Page
Statements of Assets, Liabilities and Trust Corpus
as of December 31, 1993 and 1992 ............................... 47
Statements of Cash Earnings and Distributions for the years
ended December 31, 1993, 1992, and 1991 ........................ 48
Statements of Changes in Trust Corpus for the years
ended December 31, 1993, 1992, and 1991 ........................ 49
Notes to Financial Statements .................................. 50
Independent Auditors' Report ................................... 46
(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. Form of Trust Agreement (incorporated by reference to Exhibit 6 to
the Form 8-A Registration Statement of BP Prudhoe Bay Royalty
Trust, Commission File No. 1-10243).
10.1 Form of Trust Conveyance dated February 28, 1989 (incorporated by
reference to Exhibit 6 to the Form 8-A Registration Statement of
BP Prudhoe Bay Royalty Trust, Commission File No. 1-10243).
10.2 Form of Overriding Royalty Conveyance dated February 27, 1989
(incorporated by reference to Exhibit 6 to the Form 8-A
Registration Statement of BP Prudhoe Bay Royalty Trust, Commission
File No. 1-10243).
16. Letter of Ernst & Whinney dated June 15, 1989 re change in
certifying accountant (incorporated by reference to Exhibit 16 to
Form 8-K Current Report of BP Prudhoe Bay Royalty Trust,
Commission File No. 1-10243).
60
<PAGE>
<PAGE>
23. Consent of Expert - (See Exhibit 23.1 attached hereto).
27. Financial Data Schedule - (See Exhibit 27.1 attached hereto).
ALL OTHER EXHIBITS HAVE BEEN OMITTED BECAUSE THEY ARE EITHER NOT APPLICABLE
OR NOT REQUIRED.
(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 ending in December 31, 1993.
61
<PAGE>
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
BP PRUDHOE BAY ROYALTY TRUST
THE BANK OF NEW YORK, as Trustee
By: /s/ Walter Gitlin
-----------------
Walter Gitlin
Vice President
March 29, 1994
The Registrant, BP Prudhoe Bay Royalty Trust, has no principal
executive officer, principal financial officer, board of directors or
persons performing similar functions. Accordingly, no additional signatures
are available and none have been provided.
62
<PAGE>
<PAGE>
EXHIBIT 23.1
CONSENT OF MILLER AND LENTS, LTD.
We hereby consent to the inclusion of and references to our report
dated February 25, 1994 regarding the BP Prudhoe Bay Royalty Trust in the
Trust's Annual Report on Form 10-K for the year ended December 31, 1993.
MILLER AND LENTS, LTD.
By: /s/ Irwin L. Levy
-----------------
Irwin L. Levy
Chairman of the Board
March 25, 1994
Houston, Texas
64
<PAGE>
<PAGE>
EXHIBIT 27.1
BP PRUDHOE BAY ROYALTY TRUST
FINANCIAL DATA SCHEDULE
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS AND THE STATEMENTS OF
CHANGES IN TRUST CORPUS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
ITEM NUMBER ITEM DESCRIPTION AMOUNT
----------- ---------------- ------
5-02 (1) cash and cash items $ 0
5-02 (2) marketable securities 0
5-02 (3) (a) (1) notes and accounts receivable-trade 0
5-02 (4) allowances for doubtful accounts 0
5-02 (6) inventory 0
5-02 (9) total current assets 0
5-02 (13) property, plant and equipment 0
5-02 (14) accumulated depreciation 0
5-02 (18) total assets 407,141,000
5-02 (21) total current liabilities 84,000
5-02 (22) bonds, mortgages and similar debt 0
5-02 (28) preferred stock-mandatory redemption 0
5-02 (29) preferred stock-no mandatory redemption 0
5-02 (30) common stock 0
5-02 (31) other stockholders' equity
(Trust Corpus) 407,057,000
5-02 (32) total liabilities and stockholders'
equity (Trust Corpus) 407,141,000
5-03 (b)1 (a) net sales of tangible products 0
5-03 (b)1 total royalty revenues 51,727,000
5-03 (b)2 (a) cost of tangible goods sold 0
5-03 (b)2 total costs and expenses applicable
to sales and revenues 0
5-03 (b)3 other costs and expenses 0
5-03 (b)5 provision for doubtful accounts and
notes 0
5-03 (b) (8) interest and amortization of debt
discount 0
5-03 (b) (10) income before taxes and other items 51,173,000
5-03 (b) (11) income tax expense 0
5-03 (b) (14) income/loss continuing operations 0
5-03 (b) (15) discontinued operations 0
5-03 (b) (17) extraordinary items 0
66
<PAGE>
<PAGE>
5-03 (b) (18) cumulative effect-changes in
accounting principles 0
5-03 (b) (19) net income or loss 51,173,000
5-03 (b) (20) earnings per Unit-primary 2.391
5-03 (b) (20) earnings per Unit-fully diluted 2.391
67
