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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, 1994
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
-- --
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
As of March 8, 1995, 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 $366,475,000.
Documents Incorporated by Reference: None
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TABLE OF CONTENTS
PAGE
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PART I
ITEM 1-Business................................................1
Description of the Trust.....................................1
Description of the Trust Units and the Trust Agreement.......2
Creation and Organization of the Trust....................2
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 ........................................14
Cost Adjustment Factor ..................................17
Production Taxes ........................................17
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 ............34
Industry Conditions ........................................35
Certain Tax Considerations .................................35
Employees ...............................................36
Federal Income Tax ......................................36
Classification of the Trust ........................36
Taxation of the Trust ..............................36
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Taxation of Trust Unit Holders .....................36
Taxation of Nonresident Alien Individuals,
Partnerships and Foreign Corporations ..............37
Sale of Trust Units .....................................38
Backup Withholding .................................38
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 ................................39
ITEM 6-Selected Financial Data ...............................40
ITEM 7-Management's Discussion and Analysis of Financial
Condition and Results of Operations ...................42
ITEM 8-Financial Statements and Supplementary Data ...........45
ITEM 9-Changes In Accountants ................................55
PART III
ITEM 10-Directors and Executive Officers .....................55
ITEM 11-Executive Compensation ...............................55
ITEM 12-Unit Ownership .......................................55
ITEM 13-Certain Relationships and Related Transactions .......56
PART IV
ITEM 14-Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ..............................57
SIGNATURE ....................................................59
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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 1994, 1993, and 1992. This Annual Report also includes
information with respect to 1994 production and production in past periods.
Amounts distributed with respect to 1994, 1993, and 1992, production in 1994 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.
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
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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, 1994, 1993, 1992, 1991, 1990 and 1989 were approximately $660,000, $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.
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
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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 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
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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 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.
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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 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
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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 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.
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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 Unit, and the Trust will have no other authorized or outstanding
class of equity securities. There are 21,400,000 Trust Units outstanding.
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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 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
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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 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)
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<PAGE> 14
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 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.
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<PAGE> 15
(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 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
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<PAGE> 16
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 Endicott formations. The Company's average daily net
production from its working interest in the PBU during 1994 was approximately
369,900 barrels of oil and condensate.
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<PAGE> 17
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.
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, $8.00 per barrel from January 1, 1994 through
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<PAGE> 18
December 31, 1994 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>
1995 $8.25 2008 $13.00
1996 8.50 2009 13.25
1997 8.85 2010 14.50
1998 9.30 2011 16.60
1999 9.80 2012 16.70
2000 10.00 2013 16.80
2001 10.75 2014 16.90
2002 11.25 2015 17.00
2003 11.75 2016 17.10
2004 12.00 2017 17.20
2005 12.25 2018 20.00
2006 12.50 2019 23.75
2007 12.75 2020 and 26.50 increasing
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 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, approximately 206,000,000 STB during
1993 and approximately 90,000,000 STB during 1994.
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<PAGE> 19
(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
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.
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<PAGE> 20
(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.
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
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<PAGE> 21
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. However, beginning with the second calendar quarter
(April- June) of 1995, $0.02 per barrel of this surcharge will be suspended
because the State spill response fund will have reached $50 million. In the
event the balance of that fund falls below $50 million, the $0.02 per barrel
will be reinstated until the fund balance again reaches $50 million. The
remaining $0.03 per barrel is not effected by the fund's balance and will
continue to be imposed at all times.
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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<PAGE> 22
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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<PAGE> 23
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, 1993 and 1994,
produced on average 1.4 million, 1.3 million, 1.3 million, 1.2 million, 1.1
million and 1 million barrels of oil and condensate per day, respectively. The
Field is the largest producing field in North America. As of January 1, 1995,
approximately 8.64 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
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<PAGE> 24
10% per year. Field development is well advanced with approximately $16.3
billion gross capital spent and a total of about 1,227 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
21
<PAGE> 25
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:
PRUDHOE BAY UNIT
OWNERSHIP BY PARTICIPATING AREA
(AS OF JANUARY 1, 1995)
<TABLE>
<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 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
22
<PAGE> 26
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.
23
<PAGE> 27
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, 1995, there were about 995 producing oil wells, 35 gas
reinjection wells, 55 water injection wells and 117 water and miscible gas
injection wells in the Field. In terms of individual well performance, oil
production rates range from 100 to 6,500 BOPD. Currently, the average well
production rate is about 965 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 1994 share of oil and condensate (net of State of
Alaska royalty) was as follows:
PRUDHOE BAY UNIT
1994 PRODUCTION
(BARRELS PER DAY)
<TABLE>
<CAPTION>
Company Net
Field Share
--------- -------
<S> <C> <C>
Oil .............................. 785,545 348,384
Condensate ....................... 177,450 21,489
Total ............................ 962,995 369,873
</TABLE>
The Company's net proved remaining reserves of oil and condensate in the
PBU as of December 31, 1994 were 1,395,000,000 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 2014. 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,
1994 the Per Barrel Royalty will be zero following the year 2009. 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 of Proved Reserves to Current
Reserves (as defined in CHARGEABLE COSTS) do not meet certain specific levels
(see CHARGEABLE COSTS). The Company has added and anticipates adding to its
proved reserves. Even if expected reservoir performance does not change, the
estimated reserves, economic life, and future revenues attributable to the BP
Prudhoe Bay Royalty Trust may change significantly in the future. This may
result from changes in the West Texas Intermediate Price or from
24
<PAGE> 28
changes in other prescribed variables utilized in calculations defined by
the Overriding Royalty Conveyance. See Report of Miller and Lents, Ltd.,
Independent Petroleum Consultants, below.
25
<PAGE> 29
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
February 28, 1995
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street 21 W
New York, New York 10286
Re: Estimates of Proved Reserves,
Future Production Rates, and
Future Net Revenues for the
BP Prudhoe Bay Royalty Trust
As of December 31, 1994
Gentlemen:
This letter report is a summary of investigations performed in accordance
with our engagement by you as described in Section 4.8(d) of the Overriding
Royalty Conveyance dated February 27, 1989, between BP Exploration (Alaska)
Inc., and The Standard Oil Company. The investigations included reviews of the
estimates of Proved Reserves and production rate forecasts of oil and condensate
made by BP Exploration (Alaska) Inc. attributable to the BP Prudhoe Bay Royalty
Trust as of December 31, 1994. Additionally, we reviewed calculations of the
resulting Estimated Future Net Revenues and Present Value of Estimated Future
Net Revenues attributable to the BP Prudhoe Bay Royalty Trust.
The estimates and calculations reviewed are summarized in the report
prepared by BP Exploration (Alaska) Inc. and transmitted with a cover letter
dated February 17, 1995, addressed to Ms. Marie Trimboli of The Bank of New York
and signed by Mr. David K. Woodward. Reviews were also performed by Miller and
Lents, Ltd. during this year or in previous years of (1) the procedures for
estimating and documenting Proved Reserves, (2) the estimates of in-place
reservoir volumes, (3) the estimates of recovery factors and production profiles
for the various areas, pay zones, projects, and recovery processes that are
included in the estimate of Proved Reserves, (4) the production strategy and
procedures for implementing that strategy, (5) the sufficiency of the data
available for making estimates of Proved Reserves and production profiles, and
(6) pertinent provisions of
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MILLER AND LENTS, LTD.
the Prudhoe Bay Unit Operating Agreement, the Issues Resolution Agreement, the
Overriding Royalty Conveyance, the Trust Conveyance, the BP Prudhoe Bay Royalty
Trust Agreement, and other related documents referenced in the Form F-3
Registration Statement filed with the Securities and Exchange Commission on
August 7, 1989, by BP Exploration (Alaska) Inc.
Proved Reserves were estimated by BP Exploration (Alaska) Inc. in
accordance with the definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a). Estimated Future Net Revenues and Present Value of
Estimated Future Net Revenues are not intended and should not be interpreted to
represent fair market values for the estimated reserves.
The Prudhoe Bay (Permo-Triassic) Reservoir is defined in the Prudhoe Bay
Unit Operating Agreement. The Prudhoe Bay Unit is an oil and gas unit situated
on the North Slope of Alaska. The BP Prudhoe Bay Royalty Trust is entitled to a
royalty payment on 16.4246 percent of the first 90,000 barrels of the actual
average daily net production of oil and condensate for each calendar quarter
from the BP Exploration (Alaska) Inc. working interest in the Prudhoe Bay Unit.
The payment amount depends upon the Per Barrel Royalty which, in turn, depends
upon the West Texas Intermediate Price, the Chargeable Costs, the Cost
Adjustment Factor, and Production Taxes, all of which are defined in the
Overriding Royalty Conveyance. "Barrel" as used herein means Stock Tank Barrel
as defined in the Overriding Royalty Conveyance.
Our reviews do not constitute independent estimates of the reserves and
annual production rate forecasts for the areas, pay zones, projects, and
recovery processes examined. We relied upon the accuracy and completeness of
information provided by BP Exploration (Alaska) Inc. with respect to pertinent
ownership interests and various other historical, accounting, engineering and
geological data.
As a result of our cumulative reviews, based on the foregoing, we conclude
that:
1. A large body of basic data and detailed analyses are available and
were used in making the estimates. In our judgment, the quantity and
quality of currently available data on reservoir boundaries, original
fluid contacts, and reservoir rock and fluid properties are sufficient
to indicate that any future revisions to the estimates of total
original in-place volumes should be minor. Furthermore, the data and
analyses on recovery factors and future production rates are
sufficient to support the Proved Reserves estimates.
2. The methods and procedures employed to accumulate and evaluate the
necessary information and to estimate, document, and reconcile
reserves, annual production rate forecasts, and future net revenues
are effective and are in accordance with generally
27
<PAGE> 31
MILLER AND LENTS, LTD.
accepted geological and engineering practice in the petroleum
industry.
3. Based on our limited independent tests of the computations of
reserves, production flowstreams, and future net revenues, such
computations were performed in accordance with the methods and
procedures described to us.
4. The estimated net remaining Proved Reserves attributable to the BP
Prudhoe Bay Royalty Trust as of December 31, 1994, of 81.0 million
barrels of oil and condensate are, in the aggregate, reasonable. All
81.0 million barrels are Proved Developed Reserves.
5. Utilizing the specified procedures outlined in Financial Accounting
Standards Board Statement of Financial Accounting Standards No. 69, BP
Exploration (Alaska) Inc. calculated that as of December 31, 1994,
production of the Proved Reserves will result in Estimated Future Net
Revenues of $257 million and Present Value of Estimated Future Net
Revenues of $163 million to the BP Prudhoe Bay Royalty Trust. These
estimates are reasonable.
6. BP Exploration (Alaska) Inc. estimated that, as of December 31, 1994,
668.0 million barrels of Proved Reserves have been added to Current
Reserves. This estimate is reasonable. Current Reserves are defined in
the Overriding Royalty Conveyance as net Proved Reserves of 2,035.6
million barrels as of December 31, 1987. Net additions to Proved
Reserves after December 31, 1987 affect the Chargeable Costs that are
used to calculate the Per Barrel Royalty paid to the BP Prudhoe Bay
Royalty Trust.
7. The BP Exploration (Alaska) Inc. projection that its net production of
oil and condensate from Proved Reserves will continue at an average
rate exceeding 90,000 barrels per day until the year 2014 is
reasonable. As long as the Per Barrel Royalty has a positive value,
average daily production attributable to the BP Prudhoe Bay Royalty
Trust will remain constant until the net production falls below 90,000
barrels per day; thereafter, production attributable to the BP Prudhoe
Bay Royalty Trust will decline with the BP Exploration (Alaska) Inc.
production. However, the Per Barrel Royalty will not have a positive
value if the West Texas Intermediate Price is less than the sum of the
per barrel Chargeable Costs and per barrel Production Taxes,
appropriately adjusted in accordance with the Overriding Royalty
Conveyance. Under such circumstances, average daily production
attributable to the BP Prudhoe Bay Royalty Trust will have no value
and therefore will not contribute to the reserves regardless of the BP
Exploration (Alaska) Inc. net production level.
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<PAGE> 32
MILLER AND LENTS, LTD.
8. Based on the West Texas Intermediate Price of $17.75 per barrel on
December 31, 1994, current Production Taxes, and the Chargeable Costs
adjusted as prescribed by the Overriding Royalty Conveyance, the
projection that royalty payments will continue through the year 2009
is reasonable. BP Exploration (Alaska) Inc. expects continued economic
production at a declining rate through the year 2030; however, for the
economic conditions and production forecast as of December 31, 1994,
the Per Barrel Royalty will be zero following the year 2009.
Therefore, no reserves are currently attributed to the BP Prudhoe Bay
Royalty Trust after that date.
9. Even if expected reservoir performance does not change, the estimated
reserves, economic life, and future revenues attributable to the BP
Prudhoe Bay Royalty Trust may change significantly in the future. This
may result from changes in the West Texas Intermediate Price or from
changes in other prescribed variables utilized in calculations defined
by the Overriding Royalty Conveyance.
Estimates of ultimate and remaining reserves and production scheduling
depend upon assumptions regarding expansion or implementation of alternative
projects or development programs and upon strategies for production
optimization. BP Exploration (Alaska) Inc. has continual reservoir management,
surveillance, and planning efforts dedicated to (1) gathering new information,
(2) improving the accuracy of its reserves and production capacity estimates,
(3) recognizing and exploiting new opportunities, (4) anticipating potential
problems and taking corrective actions, and (5) identifying, selecting, and
implementing optimum recovery program and cost reduction alternatives. Given
this significant effort and ever-changing economic conditions, estimates of
reserves and production profiles will change periodically.
The current estimate of Proved Reserves includes only those projects or
development programs that are deemed reasonably certain to be implemented, given
current economic and regulatory conditions. Future projects, development
programs, or operating strategies different from those assumed in the current
estimates may change future estimates and affect recoveries. However, because
several complementary and alternative projects are being considered for recovery
of the remaining oil in the reservoir, a decision not to implement a currently
planned project may allow scope expansion or implementation of another project,
thereby increasing the overall likelihood of recovering the reserves.
Future production rates will be controlled by facilities limitations and
upsets, well downtime, and the effectiveness of programs to optimize production
and costs. BP Exploration (Alaska) Inc. currently expects continued economic
production from the reservoir at a declining rate through the year 2030.
Additional drilling, workovers, facilities modifications, new recovery projects,
and programs for production enhancement and optimization are expected to
mitigate but not eliminate
29
<PAGE> 33
MILLER AND LENTS, LTD.
the anticipated future decline in gross oil and condensate production
capacity.
In making its future production rate forecasts, BP Exploration (Alaska)
Inc. provided for normal downtime and planned facilities upsets. Although
allowances for unplanned upsets are also considered in the estimates, the
studies do not provide for any impediments to crude oil production as a
consequence of major disruptions.
Under current economic conditions, gas from the Alaskan North Slope, except
for minor volumes, cannot be marketed commercially. Oil and condensate
recoveries are expected to be greater as a result of continued reinjection of
produced gas than the recoveries would be if major volumes of produced gas were
being sold. No major gas sale is assumed in the current estimates. If major gas
sales are determined to be economically viable in the future, BP Exploration
(Alaska) Inc. estimates that such sales would not actually commence until eight
to ten years after such a determination. In the event that major gas sales are
initiated, ultimate oil and condensate recoveries may be reduced from the
current estimates unless recovery projects other than those included in the
current estimates are implemented.
Large volumes of natural gas liquids are likely to be produced and marketed
in the future whether or not major gas sales become viable. Natural gas liquids
reserves are not included in the estimates cited herein. The BP Prudhoe Bay
Royalty Trust is not entitled to royalty payments from production or sales of
natural gas or natural gas liquids.
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on accepted
standards of professional investigation but are subject to those generally
recognized uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies and market
conditions different from those reflected in this study or disruption of
existing transportation routes or facilities may cause the total quantity of oil
or condensate to be recovered, actual production rates, prices received, or
operating and capital costs to vary from those reviewed in this report.
Miller and Lents, Ltd., is an independent oil and gas consulting firm. None
of the principals of this firm have any direct financial interests in BP
Exploration (Alaska) Inc. or its parent or any related companies or in the BP
Prudhoe Bay Royalty Trust. Our fee is not contingent upon the results of our
work or report, and we have not performed other services for
30
<PAGE> 34
MILLER AND LENTS, LTD.
BP Exploration (Alaska) Inc. or the BP Prudhoe Bay Royalty Trust that would
affect our objectivity.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ William P. Koza
---------------------------------------------
William P. Koza
Vice President
WPK/hsd
31
<PAGE> 35
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, 1994 ($17.75 per barrel), 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 Note 5 thereto.
Estimated net proved reserves allocable to the Trust as of December 31,
1994, December 31, 1993 and December 31, 1992 were 80,991,000 barrels,
43,193,000 barrels and 94,306,000 barrels, respectively. See "Financial
Statements" and Note 5 thereto. The decrease from December 31, 1992 to
December 31, 1993 reflects the excess of production over additions and changes
in timing of production and the decrease in the WTI Price from $19.50 per
barrel on December 31, 1992 to $14.15 per barrel on December 31, 1993. The
increase from December 31, 1993 to December 31, 1994 reflects the increase in
the WTI Price from $14.15 per barrel on December 31, 1993 to $17.75 per barrel
on December 31, 1994. Proved developed reserves allocable to the Trust as of
December 31, 1994, December 31, 1993 and December 31, 1992 were 80,991,000
barrels, 43,193,000 barrels and 79,420,000 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, heavy
oil tar recovery and development of the smaller reservoirs. While there is no
assurance that the PBU working
32
<PAGE> 36
interest owners will make any such investments, they 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
33
<PAGE> 37
from each half of the Field. At Pump Station 1, Alyeska Pipeline Service
Company, the pipeline operator, meters the oil and pumps it south to Valdez
where it is either loaded onto marine tankers or stored temporarily. It takes
the oil about six days to make the trip in the 48-inch diameter pipeline.
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, 1994 and 1995 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. A further protest has been filed by the State of
Alaska relating to the 1995 tariff challenging the inclusion of certain expenses
incurred in remediation of matters connected with National Electrical Codes.
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.
HISTORICAL PRODUCTION
<TABLE>
<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
1994 ....................... 369,900
</TABLE>
34
<PAGE> 38
(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.
INDUSTRY CONDITIONS
The production of oil and gas in Alaska is affected by many state and
federal regulations with respect to allowable rates of production, marketing,
environmental matters and pricing. Future regulations could change allowable
rates of production or the manner in which oil and gas operations may be
lawfully conducted.
In general, the Company's oil and gas activities are subject to laws and
regulations relating to environmental quality and pollution control. The Company
believes that the equipment and facilities currently being used in its
operations generally comply with the applicable legislation and regulations.
During the past few years, numerous environmental laws and regulations have
taken effect at the federal, state and local levels. Oil and gas operations are
subject to extensive federal and state regulation and to interruption or
termination by governmental authorities due to ecological and other
considerations. Although the existence of legislation and regulation has had no
material adverse effect on the Company's current method of operations, existing
and future legislation and regulations could result in the Company experiencing
delays and uncertainties in commencing projects. The ultimate impact of such
legislation and regulations cannot generally be predicted.
Oil prices are subject to international supply and demand. Political
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.
35
<PAGE> 39
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.
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.
36
<PAGE> 40
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.
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
37
<PAGE> 41
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 26 percent or
28 percent (depending on filing status and taxable income) 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 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.
38
<PAGE> 42
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 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.
PART II
ITEM 5. MARKET FOR TRUST UNITS
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 1993 and 1994 and the
distributions paid by the Trust for the periods presented.
<TABLE>
<CAPTION>
Distributions Per
Trust Unit
----------
High Low 1993 1994
1993 1994 1993 1994 _____ _____
<S> <C> <C> <C> <C> <C> <C>
First Quarter $31.750 $27.000 $29.500 $23.000 0.590 0.228
Second Quarter $31.625 $24.000 $27.750 $19.125 0.595 0.396
Third Quarter $29.625 $24.000 $26.125 $21.250 0.499 0.436
Fourth Quarter $29.625 $22.375 $23.875 $15.750 0.424 0.390
</TABLE>
39
<PAGE> 43
As of March 21, 1995, there were 1,708 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> 44
The following table presents in summary form selected financial
information regarding the Trust.
BP PRUDHOE BAY ROYALTY TRUST
Statements of Cash Earnings and Distributions
For each of the years in the five-year period ended
December 31, 1994, 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)
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990 1989
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Royalty revenues $ 32,401 51,727 65,250 87,010 76,788 40,776
Trust administrative
expenses 658 554 413 412 457 170
--------- ---------- ---------- ---------- ---------- ----------
Cash earnings 31,743 51,173 64,837 86,598 76,331 40,606
========== ========== ========== ========== ========== ==========
Cash distributions 31,743 51,173 64,837 86,598 76,331 40,606
========== ========== ========== ========== ========== ==========
Cash distributions
per unit $ 1.483 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 21,400,000
=========== ========== ========== ========== ========== ==========
</TABLE>
41
<PAGE> 45
ITEM 7. 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.
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.
ACTUAL RESULTS
During 1994 the Trust received payments with respect to the Royalty
Interest in the aggregate amount of $32,401,000 and made distributions to Unit
holders in the aggregate amount of $31,743,000. The payment with respect to the
Royalty Interest for the calendar quarter ended December 31, 1994, which was
paid to the Trust on January 17, 1995, was $8,478,000. 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.
42
<PAGE> 46
CALENDAR YEARS 1994, 1993, AND 1992
<TABLE>
<CAPTION>
1/1-3/31 4/1-6/30 7/1-9/3 10/1-12/31
-------- -------- ------- ----------
1994 1993 1992 1994 1993 1992 1994 1993 1992 1994 1993 1992
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Average WTI
Price $14.80 $19.85 $18.94 $17.79 $19.76 $21.20 $18.49 $17.77 $21.67 $17.67 $16.43 $20.50
Chargeable
Costs 8.00 6.75 6.00 8.00 6.75 6.00 8.00 6.75 6.00 8.00 6.75 6.00
Cost
Adjustment
Factor 1.180 1.171 1.134 1.180 1.180 1.143 1.192 1.180 1.153 1.192 1.180 1.162
Adjusted
Chargeable 9.44 7.90 6.80 9.44 7.96 6.86 9.53 7.96 6.92 9.53 7.96 6.97
Costs
Production
Taxes 1.48 2.24 2.13 1.93 2.22 2.46 2.02 1.92 2.53 1.90 1.72 2.34
Per Barrel
Royalty 3.88 9.71 10.00 6.42 9.57 11.88 6.93 7.88 12.23 6.23 6.74 11.18
</TABLE>
(All Figures after rounding)
43
<PAGE> 47
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 in accordance with the discussion
above under "Production Taxes".
44
<PAGE> 48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
BP PRUDHOE BAY ROYALTY TRUST
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
<S> <C>
Independent Auditors' Report ................................. 46
Statements of Assets, Liabilities and Trust Corpus
as of December 31, 1994 and 1993.............................. 47
Statements of Cash Earnings and Distributions for
the years ended December 31, 1994, 1993 and 1992.............. 48
Statements of Changes in Trust Corpus for the years
ended December 31, 1994, 1993 and 1992........................ 49
Notes to Financial Statements................................. 50
</TABLE>
45
<PAGE> 49
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, 1994 and 1993,
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,
1994. 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, 1994 and 1993, 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, 1994, on the basis of accounting described
in note 2.
KPMG Peat Marwick LLP
New York, New York
March 22, 1995
46
<PAGE> 50
BP PRUDHOE BAY ROYALTY TRUST
Statements of Assets, Liabilities and Trust Corpus
December 31, 1994 and 1993
(In thousands, except unit data)
<TABLE>
<CAPTION>
ASSETS 1994 1993
---- ----
<S> <C> <C>
Royalty Interest (notes 1 and 2) $ 535,000 535,000
Less: accumulated amortization (194,689) (127,859)
---------- --------
Total assets $ 340,311 407,141
========== ========
LIABILITIES AND TRUST CORPUS
Accrued expenses $ 118 84
Trust Corpus (40,000,000 units of beneficial
interest authorized, 21,400,000 units issued
and outstanding) 340,193 407,057
Contingencies (note 3)
---------- --------
Total liabilities and Trust Corpus $ 340,311 407,141
========== ========
</TABLE>
See accompanying notes to financial statements.
47
<PAGE> 51
BP PRUDHOE BAY ROYALTY TRUST
Statements of Cash Earnings and Distributions
For the Years Ended December 31, 1994, 1993 and 1992
(In thousands, except unit data)
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Royalty revenues $ 32,401 51,727 65,250
Trust administrative expenses 658 554 413
----------- ---------- ----------
Cash earnings $ 31,743 51,173 64,837
=========== ========== ==========
Cash distributions $ 31,743 51,173 64,837
=========== ========== ==========
Cash distributions per unit $ 1.483 2.391 3.030
=========== ========== ==========
Units outstanding 21,400,000 21,400,000 21,400,000
=========== ========== ==========
</TABLE>
See accompanying notes to financial statements.
48
<PAGE> 52
BP PRUDHOE BAY ROYALTY TRUST
Statements of Changes in Trust Corpus
For the Years Ended December 31, 1994, 1993 and 1992
(In thousands)
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Trust Corpus at beginning of year $ 407,057 437,666 467,158
Cash earnings 31,743 51,173 64,837
Decrease (increase) in
accrued Trust expenses (34) - 1
Cash distributions (31,743) (51,173) (64,837)
Amortization of Royalty Interest (66,830) (30,609) (29,493)
--------- -------- --------
Trust Corpus at end of year $ 340,193 407,057 437,666
========= ======== ========
</TABLE>
See accompanying notes to financial statements.
49
<PAGE> 53
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
December 31, 1994, 1993 and 1992
(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 an overriding royalty
interest (the "Royalty Interest") to the Trust. The Trust was formed for
the sole purpose of owning and administering the Royalty Interest. The
Royalty Interest represents the right to receive, effective February 28,
1989, a per barrel royalty (the "Per Barrel Royalty") on 16.4246% of the
lesser of (a) the first 90,000 barrels of the average actual daily net
production of oil and condensate per quarter or (b) the average actual
daily net production of oil and condensate per quarter from the Company's
working interest in the Prudhoe Bay Field (the "Field") 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 Interest. The
Trustee, subject to certain conditions, is obligated to establish cash
reserves and borrow funds to pay liabilities of the Trust when they
become due. The Trustee may sell Trust properties only (a) as authorized
by a vote of the Trust Unit holders, (b) when necessary to provide for
the payment of specific liabilities of the Trust then due (subject to
certain conditions) or (c) upon termination of the Trust. Each Trust Unit
issued and outstanding represents an equal undivided share of beneficial
interest in the Trust. Royalty payments are received by the Trust and
distributed to Trust Unit holders, net of Trust expenses, in the month
succeeding the end of each calendar quarter. The Trust will terminate
upon the first to occur of the following events:
(a) On or prior to December 31, 2010: upon a vote of Trust Unit
holders of not less than 70% of the outstanding Trust Units.
(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).
(Continued)
50
<PAGE> 54
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(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
43,193,000, 94,306,000 and 98,141,000 barrels were used to
calculate the amortization of the Royalty Interest for the years
ended December 31, 1994, 1993 and 1992, 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
$12.39, $5.67 and $5.45 for the years ended December 31, 1994,
1993 and 1992, respectively. The remaining unamortized balance
of the net overriding Royalty Interest at December 31, 1994 is
not necessarily indicative of the fair market value of the
interest held by the Trust.
While these statements differ from financial statements prepared in
accordance with generally accepted accounting principles, the cash basis
of reporting revenues and distributions is considered to be the most
meaningful because quarterly distributions to the Unit holders are based
on net cash receipts
The conveyance of the Royalty Interest by Standard Oil to the Trust
was accounted for as a purchase transaction. On February 28, 1989,
Standard Oil sold 13,360,000 Trust Units to a group of institutional
investors for $334 million in a private placement. For financial
reporting purposes, the Trust's management valued the remaining Trust
Units owned by Standard Oil (8,040,000 units) at a per unit value
equivalent to the amount paid by the investors in the private placement.
(3) INCOME TAXES
The Trust files its federal tax return as a grantor trust subject to
the provisions of subpart E of Part I of Subchapter J of the Internal
Revenue Code of 1986, as amended, rather than as an association taxable
as a corporation. The Unit holders are treated as the owners of Trust
income and Corpus, and the entire taxable income of the Trust will be
reported by the Unit holders on their respective tax returns.
If the Trust were determined to be an association taxable as a
corporation, it would be treated as an entity taxable as a corporation on
the taxable income from the Royalty Interest, the Trust Unit holders
would be treated as shareholders, and distributions to Trust Unit holders
would not be deductible in computing the Trust's tax liability as an
association.
(Continued)
51
<PAGE> 55
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(4) SUMMARY OF QUARTERLY RESULTS (UNAUDITED)
A summary of selected quarterly financial information for the years
ended December 31, 1994 and 1993 is as follows (in thousands, except unit
data):
<TABLE>
<CAPTION>
1ST 2ND 3RD 4TH
QUARTER QUARTER QUARTER QUARTER
------- ------ ------ ------
<S> <C> <C> <C> <C>
1994
Royalty revenues $ 9,172 5,164 8,640 9,425
Trust administrative expenses 100 284 171 103
------- ------ ------ ------
Cash earnings 9,072 4,880 8,469 9,322
Cash distributions 9,072 4,880 8,469 9,322
Cash distributions per unit 0.424 0.228 0.396 0.436
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
</TABLE>
(5) SUPPLEMENTAL RESERVE INFORMATION AND STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOW RELATING TO PROVED RESERVES (UNAUDITED)
Pursuant to Statement of Financial Accounting Standards No. 69 -
"Disclosures About Oil and Gas Producing Activities" ("FASB 69"), the
Trust is required to include in its financial statements supplementary
information regarding estimates of quantities of proved reserves
attributable to the Trust and future net cash flows.
Estimates of proved reserves are inherently imprecise and subjective
and are revised over time as additional data becomes available. Such
revisions may often be substantial. Information regarding estimates of
proved reserves attributable to the combined interests of the Company and
the Trust were based on Company-prepared reserve estimates. The Company's
reserve estimates are believed to be reasonable and consistent with
presently known physical data concerning the size and character of the
Field.
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, 1994 ($17.75 per barrel),
December 31, 1993 ($14.15 per barrel) and December 31, 1992 ($19.50 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.
(Continued)
52
<PAGE> 56
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(5), Continued
In addition to production estimates and prices, reserve volumes
attributable to the Trust are affected by the amount of Chargeable Costs
that will be deducted in determining the Per Barrel Royalty. The Royalty
Interest includes a provision under which, in years subsequent to 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, 1994, 1993 and 1992 based on the Company's latest
reserve estimate at such time, the WTI Prices on December 31, 1994, 1993
and 1992 and a reduction in Chargeable Costs in years subsequent to 1995,
were estimated to be 81, 43 and 94 million barrels, respectively (of
which 81, 43 and 79 million barrels, respectively, are proved developed).
The standardized measure of discounted future net cash flow relating
to proved reserves disclosure required by FASB 69 assigns monetary
amounts to proved reserves based on current prices. This discounted
future net cash flow should not be construed as the current market value
of the Royalty Interest. A market valuation determination would include,
among other things, anticipated price increases and the value of
additional reserves not considered proved at the present time or reserves
that may be produced after the currently anticipated end of field life.
At December 31, 1994, 1993 and 1992 the standardized measure of
discounted future net cash flow relating to proved reserves attributable
to the Trust (estimated in accordance with the provisions of FASB 69),
based on the WTI Prices on those dates of $17.75, $14.15 and $19.50,
respectively, were as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1994 1993 1992
--------- ------- --------
<S> <C> <C> <C>
Future net cash flows $ 257,080 83,735 498,966
10% annual discount for
estimated timing of
cash flows (93,935) (18,563) (214,670)
--------- ------- --------
Standardized measure of
discounted future net
cash flow relating to
proved reserves (a) $ 163,145 65,172 284,296
========= ======= ========
</TABLE>
(a) The standardized measure of discounted future net cash flow
relating to proved reserves, estimated without reducing
Chargeable Costs in years subsequent to 1995, would be $154,200,
$65,174 and $228,566 at December 31, 1994, 1993 and 1992,
respectively.
(Continued)
53
<PAGE> 57
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
(5), Continued
The following are the principal sources of the change in the
standardized measure of discounted future net cash flows (in
thousands):
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Revisions of prior estimates:
Reserve volumes $ 28,853 16,747 1,272
WTI price 115,530 (245,140) 26,168
Chargeable costs - inflation (3,300) (8,537) (20,433)
Production taxes (17,093) 37,347 (2,760)
Other (827) (2,280) (2,564)
--------- -------- -------
123,163 (201,863) 1,683
Royalty income received (b) (31,707) (45,691) (61,273)
Accretion of discount 6,517 28,430 31,262
--------- -------- -------
Net increase (decrease) during the year $ 97,973 (219,124) (28,328)
========= ======== =======
</TABLE>
(b) Royalty income received for 1994, 1993 and 1992 includes the
royalty applicable to the period October 1, 1994 through December
31, 1994 ($8,478), October 1, 1993 through December 31, 1993
($9,172) and October 1, 1992 through December 31, 1992 ($15,209),
which was received by the Trust in January 1995, 1994 and 1993,
respectively.
The changes in quantities of proved oil and condensate were as follows
(thousands of barrels):
<TABLE>
<S> <C>
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
Production (5,395)
Change in timing of estimated production 43,193
------
Estimated net proved reserves of oil
and condensate at December 31, 1994 80,991
======
Proved developed reserves:
December 31, 1992 79,424
======
December 31, 1993 43,193
======
December 31, 1994 80,991
======
</TABLE>
54
<PAGE> 58
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 (now KPMG Peat
Marwick LLP) 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.
As of March 21, 1995 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, 1994, which filings set forth
the following:
<TABLE>
<CAPTION>
Name No. of Units Percentage
<S> <C> <C>
J.P. Morgan & Co., Inc. 2,065,100(1) 9.6
23 Wall Street
New York, N.Y. 10007
</TABLE>
55
<PAGE> 59
<TABLE>
<CAPTION>
<S> <C> <C>
Prudential Insurance Company
of America 3,001,600(1) 14
3 Gateway Center
Newark, N.J. 07102
</TABLE>
(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.
56
<PAGE> 60
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:
<TABLE>
<CAPTION>
Page
<S> <C>
Statements of Assets, Liabilities and Trust Corpus
as of December 31, 1994 and 1993 ............................... 47
Statements of Cash Earnings and Distributions for the years
ended December 31, 1994, 1993, and 1992 ........................ 48
Statements of Changes in Trust Corpus for the years
ended December 31, 1994, 1993, and 1992 ........................ 49
Notes to Financial Statements .................................. 50
Independent Auditors' Report ................................... 46
</TABLE>
(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
<TABLE>
<S> <C>
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).
23. Consent of Expert - (See Exhibit 23.1 attached hereto).
</TABLE>
57
<PAGE> 61
<TABLE>
<S> <C>
27. Financial Data Schedule - (See Exhibit 27.1 attached hereto).
</TABLE>
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, 1994.
58
<PAGE> 62
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, 1995
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.
59
<PAGE> 63
EXHIBIT INDEX
-------------
<TABLE>
<S> <C>
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).
23. Consent of Expert - (See Exhibit 23.1 attached hereto).
27. Financial Data Schedule - (See Exhibit 27.1 attached hereto).
</TABLE>
<PAGE> 1
EXHIBIT 23.1
CONSENT OF MILLER AND LENTS, LTD.
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
March 25, 1995
BP Prudhoe Bay Royalty Trust
c/o The Bank of New York, Trustee
101 Barclay Street, 21st Floor West
New York, New York 10286
Re: Securities and Exchange Commission
Form 10K of the
BP Prudhoe Bay Royalty Trust
Gentlemen:
The firm of Miller and Lents, Ltd. consents to the use of its name and to
the use of its report dated February 28, 1995 regarding the Estimates of Proved
Reserves, Future Annual Production Rates and Future Net Revenues for the BP
Prudhoe Bay Royalty Trust As of December 31, 1994, which report is to be
included in Form 10-K to be filed by the BP Prudhoe Bay Royalty Trust with the
Securities and Exchange Commission.
Miller and Lents, Ltd. has no interests in the BP Prudhoe Bay Royalty
Trust, or in any of its affiliated companies or subsidiaries and is not to
receive any such interest as payment for such report and has no director,
officer, or employee employed or otherwise connected with the BP Prudhoe Bay
Royalty Trust. We are not employed by the BP Prudhoe Bay Royalty Trust on a
contingent basis.
Yours very truly,
MILLER AND LENTS, LTD.
By: /s/ Walter Crow
---------------------------------------
Walter Crow
Chairman
64
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENTS OF ASSETS, LIABILITES AND TRUST CORPUS AND THE STATEMENTS OF CHANGES
IN TRUST CORPUS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 0
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 0
<DEPRECIATION> 0
<TOTAL-ASSETS> 340,311,000
<CURRENT-LIABILITIES> 118,000
<BONDS> 0
<COMMON> 0
0
0
<OTHER-SE> 340,193,000
<TOTAL-LIABILITY-AND-EQUITY> 340,311,000
<SALES> 0
<TOTAL-REVENUES> 32,401,000
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 31,743,000
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 31,743,000
<EPS-PRIMARY> 1.483
<EPS-DILUTED> 1.483
</TABLE>
