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, 1996
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
of incorporation or organization) Identification No.)
THE BANK OF NEW YORK, TRUSTEE
101 BARCLAY STREET, 21W
NEW YORK, NEW YORK 10286
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (212) 815-5092
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange On Which
Title of Each Class Registered
------------------- ------------------------------
UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K [X]
As of March 27, 1997, 21,400,000 Units of Beneficial Interest were
outstanding. The aggregate market value of Units (based on the closing price
of the Units in New York Stock Exchange composite trading on March 26, 1997 as
reported in The Wall Street Journal) held by nonaffiliates was approximately
$337,050,000.
Documents Incorporated by Reference: None
i
TABLE OF CONTENTS
PART I 1
ITEM 1. BUSINESS 1
INTRODUCTION 1
THE TRUST 2
Duties and Limited Powers of Trustee 2
Employees 2
Property of the Trust 2
Amendment of the Trust Agreement 3
Resignation or Removal of Trustee 4
Liabilities and Contingent Reserves 4
Termination of the Trust 5
Voting Rights of Holders of Units 5
THE ROYALTY INTEREST 6
Royalty Production 6
Per Barrel Royalty 6
WTI Price 6
Chargeable Costs 7
Cost Adjustment Factor 8
Production Taxes 9
Per Barrel Royalty Calculations 9
Potential Conflicts of Interest 10
THE UNITS 11
Units 11
Distributions of Income 11
Reports to Unit Holders 12
Limited Liability of Unit Holders 13
Possible Divestiture of Units 13
Issuance of Additional Units 14
THE BP SUPPORT AGREEMENT 14
THE PRUDHOE BAY UNIT 15
General 15
Geology 15
Oil Characteristics 16
Prudhoe Bay Unit Operation and Ownership 16
Historical Production 17
Transportation of Prudhoe Bay Oil 17
Reservoir Management 18
Reserve Estimates 18
INDEPENDENT OIL AND GAS CONSULTANTS' REPORT 21
INDUSTRY CONDITIONS 26
CERTAIN TAX CONSIDERATIONS 26
Federal Income Tax 26
Classification of the Trust 26
General Features of Grantor Trust Taxation 26
Taxation of Unit Holders 27
Depletion Deductions 27
Taxation of Foreign Unit Holders 28
Sale of Units 28
Backup Withholding 28
State Income Taxes 29
ITEM 2. PROPERTIES 29
ITEM 3. LEGAL PROCEEDINGS 29
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS 29
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PART II 30
ITEM 5. MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS 30
ITEM 6. SELECTED FINANCIAL DATA 31
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 33
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE 44
PART III 44
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 44
ITEM 11. EXECUTIVE COMPENSATION 44
ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT 44
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 45
PART IV 46
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K 46
SIGNATURES 47
INDEX TO EXHIBITS 48
PART I
ITEM 1. BUSINESS
INTRODUCTION
BP Prudhoe Bay Royalty Trust (the "Trust"), a grantor trust, was created
as a Delaware business trust pursuant to the BP Prudhoe Bay Royalty Trust
Agreement dated February 28, 1989 (the "Trust Agreement") among The Standard
Oil Company ("Standard Oil"), BP Exploration (Alaska) Inc. (the "Company"),
The Bank of New York, as trustee (the "Trustee"), and F. James Hutchinson, co-
trustee (The Bank of New York (Delaware), successor co-trustee). The Company
and Standard Oil are indirect, wholly owned subsidiaries of The British
Petroleum Company p.l.c. ("BP"). The Trustee's corporate trust offices are
located at 101 Barclay Street, New York, New York 10286 and its telephone
number is (212) 815-5092.
Upon creation of the Trust, the Company conveyed to Standard Oil, and
Standard Oil, in turn, conveyed to the Trust an overriding royalty interest
(the "Royalty Interest"), which entitles the Trust to a royalty on 16.4246
percent of the first 90,000 barrels of the average actual daily net production
of oil and condensate per quarter from the working interest of the Company as
of February 28, 1989 in the Prudhoe Bay Unit located on the North Slope in
Alaska. The Royalty Interest is free of any exploration and development
expenditures.
The only assets of the Trust are the Royalty Interest assigned to the
Trust and cash or cash equivalents held by the Trustee from time to time as
reserves or for distribution. The Trust is a passive entity, and the Trustee
has been given only such powers as are necessary for the collection and
distribution of revenues from the Royalty Interest and the payment of Trust
liabilities and expenses. The beneficial interest in the Trust is divided
into equal undivided units (the "Units"). The Units are not an interest in or
an obligation of the Company, Standard Oil or BP. The Delaware Trust Act,
under which the Trust was formed, entitles holders of the Units to the same
limitation of personal liability as stockholders of a Delaware corporation.
The Company shares control of the operation of the Prudhoe Bay Unit with
other working interest owners. The operations of the Company and the other
working interest owners are governed by an agreement dated April 1, 1977 among
the State of Alaska and such working interest owners establishing the Prudhoe
Bay Unit (the "Prudhoe Bay Unit Agreement") and an agreement dated April 1,
1977 among the working interest owners governing Prudhoe Bay Unit operations
(the "Prudhoe Bay Unit Operating Agreement"). The Company has no obligation
to continue production from the Prudhoe Bay Unit or to maintain production at
any level and may interrupt or discontinue production at any time. The
operation of the Prudhoe Bay Unit is subject to normal operating hazards
incident to the production and transportation of oil in Alaska. In the event
of damage to the Prudhoe Bay Unit which is covered by insurance, the Company
has no obligation to use insurance proceeds to repair such damage and may
elect to retain such proceeds and close damaged areas to production.
The Trustee has no responsibility for the operation of the Prudhoe Bay
Unit or authority over the Company, Standard Oil or BP. The information in
this report relating to the Prudhoe Bay Unit, the calculation of the royalty
payments and certain other matters has been furnished to the Trustee by the
Company.
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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 descriptions of certain provisions of
the Trust Agreement in this section and elsewhere in this report do not
purport to be complete and are qualified by reference to the relevant
provisions of the Trust Agreement, which is filed as an exhibit to this
report.
The basic function of the Trustee is to collect income from the Royalty
Interest, to pay from the Trust's income and assets all expenses, charges and
obligations of the Trust, and to pay available cash to holders of Units. The
Bank of New York (Delaware) has been appointed co-trustee in order to satisfy
certain requirements of the Delaware Trust Act, but The Bank of New York alone
is able to exercise the rights and powers granted to the Trustee in the Trust
Agreement.
The Trust Agreement grants the Trustee only such rights and powers as are
necessary to achieve the purposes of the Trust. The Trust Agreement prohibits
the Trust from engaging in any business, any commercial activity or, with
certain exceptions, investment activity of any kind and from using any portion
of the assets of the Trust to acquire any oil and gas lease, royalty or other
mineral interest. The Trustee may sell Trust properties only as authorized by
a vote of the holders of 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 Units, and it receives an opinion of counsel to the effect that
such sale will not adversely affect the classification of the Trust as a
"grantor trust" for federal income tax purposes), or upon termination of the
Trust. Pledges or other encumbrances to secure borrowings are permitted
without a vote of holders of 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 Units, and the Trustee is obligated to distribute
the available net proceeds of any such sale to the holders of Units after
establishing reserves for liabilities of the Trust.
Except in certain circumstances, the Trustee is entitled to be
indemnified out of the assets of the Trust for any liability, expense, claim,
damage or other loss incurred by it in the performance of its duties unless
such loss results from its negligence, bad faith, or fraud or from its
expenses in carrying out such duties exceeding the compensation and
reimbursement it is entitled to under the Trust Agreement.
Employees
The Trust has no employees. All administrative functions of the Trust
are performed by the Trustee.
Property of the Trust
Except for cash and cash equivalents held by the Trustee from time to
time, the property of the Trust consists exclusively of the Royalty Interest.
The Royalty Interest was conveyed to the Trust pursuant to an Overriding
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Royalty Conveyance dated February 27, 1989 between the Company and Standard
Oil and a Trust Conveyance dated February 28, 1989 between Standard Oil and
the Trust. The Overriding Royalty Conveyance and the Trust Conveyance are
referred to collectively herein as the "Conveyance." For a description of the
terms of the Royalty Interest, see "THE ROYALTY INTEREST" below. The
discussion of the terms of the Conveyance herein is qualified in its entirety
by reference to the relevant provisions of the Overriding Royalty Conveyance
and the Trust Conveyance which are filed with the Securities and Exchange
Commission as exhibits to this report.
The interest conveyed to the Trust by the Conveyance is an overriding
royalty interest consisting of the right to receive a Per Barrel Royalty for
each barrel of Royalty Production. The meaning of these terms is more fully
described below under "THE ROYALTY INTEREST." The Trust does not have the
right to take oil and gas in kind.
The Royalty Interest constitutes a non-operational interest in minerals.
The Trust has no right to take over operations or to share in any operating
decision whatsoever with respect to the Company's working interest in the
Prudhoe Bay Unit. The Company is not obligated to continue to operate any
well or maintain in force or attempt to maintain in force any portion of its
working interest in the Prudhoe Bay Unit when, in its reasonable and prudent
business judgment such well or interest ceases to produce or is not capable of
producing oil or gas in paying quantities.
Under the terms of the Prudhoe Bay Unit Operating Agreement, if the
Company fails to pay any costs and expenses chargeable to the Company under
the Prudhoe Bay Unit Operating Agreement and the production of oil and
condensate is insufficient to pay such costs and expenses, the Royalty
Interest is chargeable with a pro rata portion of such costs and expenses and
is subject to the enforcement against it of liens granted to the operators of
the Prudhoe Bay Unit. However, in the Conveyance the Company agreed to pay
timely all costs and expenses chargeable to it and to ensure that no such
costs and expenses will be chargeable against the Royalty Interest. The Trust
is not liable for any expense, claim, damage, loss or liability incurred by
the Company or others attributable to the Company's working interest in the
Prudhoe Bay Unit or to the oil produced from it, and the Company has agreed to
indemnify the Trust and hold it harmless against any such impositions.
The Company has the right to amend or terminate the Prudhoe Bay Unit
Agreement, the Prudhoe Bay Unit Operating Agreement and any leases or
conveyances with respect to its working interest in the exercise of its
reasonable and prudent business judgment without liability to the Trust. The
Company also has the right to sell or assign all or any part of its working
interest in the Prudhoe Bay Unit, so long as the sale or assignment is
expressly made subject to the Royalty Interest and the terms and provisions of
the Conveyance.
Amendment of the Trust Agreement
The Trust Agreement may be amended without a vote of the holders of Units
to cure an ambiguity, to correct or supplement any provision of the Trust
Agreement that may be inconsistent with any other such provision or to make
any other provision with respect to matters arising under the Trust Agreement
that do not adversely affect the holders of Units. The Trust Agreement also
may be amended with the approval of a majority of the outstanding Units at a
meeting of holders of Units. However, no such amendment may alter the
4
relative rights of Unit holders, unless approved by the affirmative vote of
100 percent of the holders of Units and by the Trustee, or reduce or delay the
distributions to the holders of Units or effect certain other changes unless
approved by the affirmative vote of 80 percent of the holders of Units and by
the Trustee. No amendment will be effective until the Trustee has received a
ruling from the Internal Revenue Service or an opinion of counsel to the
effect that such modification will not adversely affect the classification of
the Trust as a "grantor trust" for federal income tax purposes or cause the
income from the Trust to be treated as unrelated business taxable income for
federal income tax purposes.
Resignation or Removal of Trustee
The Trustee may resign at any time or be removed with or without cause by
the holders of a majority of the outstanding Units. Its successor must be a
corporation organized and doing business under the laws of the United States,
any state thereof or the District of Columbia, authorized under such laws to
exercise trust powers, or a national banking association domiciled in the
United States, in either case having a combined capital, surplus and undivided
profits of at least $50,000,000 and subject to supervision or examination by
federal or state authorities. Unless the Trust already has a trustee that is
a resident of or has a principal office in the State of Delaware, then any
successor trustee will be such a resident or have such a principal office. No
resignation or removal of the Trustee shall become effective until a successor
trustee shall have accepted appointment.
Liabilities and Contingent Reserves
Because of the passive nature of the Trust's assets and the restrictions
on the power of the Trustee to incur obligations, the only liabilities
incurred by the Trust are routine administrative expenses, such as Trustee's
fees, and accounting, legal and other professional fees.
The Trustee may establish a cash reserve for the payment of material
liabilities of the Trust which may become due, if the Trustee has determined
that it is not practical to pay such liabilities out of funds anticipated to
be available for subsequent quarterly distributions and that, in the absence
of such a reserve, the trust estate is subject to the risk of loss or
diminution in value or The Bank of New York is subject to the risk of personal
liability for such liabilities. Except in certain limited circumstances,
before establishing such a reserve the Trustee must have 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 when due, and to pledge
or otherwise encumber the Trust's assets, if it determines that the cash on
hand is insufficient to pay such liabilities and that it is not practical to
pay such liabilities out of funds anticipated to be available for subsequent
quarterly distributions, 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 Units.
5
Termination of the Trust
The Trust is irrevocable and the Company has no power to terminate the
Trust. The Trust will terminate: (a) on or prior to December 31, 2010 upon a
vote of holders of not less than 70 percent of the outstanding Units, or (b)
after December 31, 2010 either (i) at such time as the net revenues from the
Royalty Interest for two successive years commencing after 2010 are less than
$1,000,000 per year, unless the net revenues during such period have been
materially and adversely affected by an event constituting force majeure, or
(ii) upon a vote of holders of not less than 60 percent of the outstanding
Units.
Upon termination of the Trust, the Company will have an option to
purchase the Royalty Interest (for cash unless holders representing 70 percent
of the Units outstanding (60 percent if the decision to terminate the Trust is
made after December 31, 2010) authorize the sale for non-cash consideration
and the Trustee has received a ruling from the Internal Revenue Service or an
opinion of counsel to the effect that such non-cash sale will not adversely
affect the classification of the Trust as a "grantor trust" for federal income
tax purposes or cause the income from the Trust to be treated as unrelated
business taxable income for federal income tax purposes) at a price equal to
the greater of (i) the fair market value of the trust estate as set forth in
an opinion of an investment banking firm or other entity qualified to give an
opinion as to the fair market value of the assets of the Trust, or (ii) the
number of outstanding Units multiplied by (a) the closing price of Units on
the day of termination of the Trust on the stock exchange on which the Units
are listed, or (b) if the Units are not listed on any stock exchange but are
traded in the over-the-counter market, the closing bid price on the day of
termination of the Trust as quoted on the NASDAQ National Market System. If
the Units are neither listed nor traded in the over-the-counter market, the
price will be the fair market value of the trust estate as set forth in the
opinion mentioned above.
If the Company does not exercise its option, the Trustee will sell the
Trust properties pursuant to procedures or material terms and conditions
approved by the vote of holders of 70 percent of the outstanding Units (60
percent if the sale is made after December 31, 2010), unless the Trustee
determines that it is not practicable to submit such procedures or terms to a
vote of the holders of Units, and the sale is effected at a price which is at
least equal to the fair market value of the trust estate as set forth in the
opinion mentioned above and pursuant to terms and conditions deemed
commercially reasonable by the investment banking firm or other entity
rendering such opinion.
After satisfying all existing liabilities and establishing adequate
reserves for the payment of contingent liabilities, the Trustee will
distribute all available proceeds to the holders of Units.
In the Trust Agreement, holders of Units have waived the right to seek or
secure any portion or distribution of the Royalty Interest or any other asset
of the Trust or any accounting during the term of the Trust or during any
period of liquidation and winding up.
Voting Rights of Holders of Units
Although holders of Units possess certain voting rights, their voting
rights are not comparable to those of shareholders of a corporation. For
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example, there is no requirement for annual meetings of holders of Units or
annual or other periodic reelection of the Trustee.
THE ROYALTY INTEREST
The Royalty Interest is a property right under Alaska law which burdens
production, but there is no other security interest in the reserves or
production revenues to which the Royalty Interest is entitled. The royalty
payable to the Trust under the Royalty Interest for each calendar quarter is
the sum of the product of (i) the Royalty Production and (ii) the Per Barrel
Royalty for each day in the quarter. The payment under the Royalty Interest
for any calendar quarter may not be less than zero nor more than the aggregate
value of the total production of oil and condensate from the Company's working
interest in the Prudhoe Bay Unit for such calendar quarter, net of the State
of Alaska royalty and less the value of any applicable payments made to
affiliates of the Company.
Royalty Production
The "Royalty Production" for each day in a calendar quarter is 16.4246
percent of the first 90,000 barrels of the actual average daily net production
of oil and condensate for such quarter from the Prudhoe Bay (Permo-Triassic)
Reservoir and allocated to the oil and gas leases owned by the Company in the
Prudhoe Bay Unit as of February 28, 1989 or as modified thereafter by any
redetermination provided under the terms of the Prudhoe Bay Unit Operating
Agreement and the Prudhoe Bay Unit Agreement (the "Subject Leases"). The
Royalty Production is based on oil produced from the oil rim and condensate
produced from the gas cap, but not on gas production or natural gas liquids
production. The actual average daily net production of oil and condensate
from the Subject Leases for any calendar quarter is the total production of
oil and condensate for such quarter, net of the State of Alaska royalty,
divided by the number of days in such quarter.
Per Barrel Royalty
The "Per Barrel Royalty" in effect for any day is an amount equal to the
WTI Price for such day less the sum of (i) the product of the Chargeable Costs
multiplied by the Cost Adjustment Factor and (ii) Production Taxes.
WTI Price
The "WTI Price" for any trading day means (i) the latest price (expressed
in dollars per barrel) for West Texas intermediate crude oil of standard
quality having a specific gravity of 40 degrees API for delivery at Cushing,
Oklahoma ("West Texas Crude"), quoted for such trading day by the Dow Jones
International Petroleum Report (which is published in The Wall Street Journal)
or if the Dow Jones International Petroleum Report does not publish such
quotes, then such price as quoted by Reuters, or if Reuters does not publish
such quotes, then such price as quoted in Platt's Oilgram Price Report, or
(ii) if for any reason such publications do not publish the price of West
Texas Crude, then the WTI Price will mean, until the price quotations
described in (i) are again available, the simple average of the daily mean
prices (expressed in dollars per barrel) quoted for West Texas Crude by one
major oil company, one petroleum broker and one petroleum trading company, in
each case unaffiliated with BP and having substantial U.S. operations. Such
7
major oil company, petroleum broker and petroleum trading company will be
designated by the Company from time to time. In the event that prices for
West Texas Crude are not quoted so as to permit the calculation of the WTI
Price, "West Texas Crude," for the purposes of calculating the WTI Price will
mean such other light sweet domestic crude oil of standard quality as is
designated by the Company and approved by the Trustee in the exercise of its
reasonable judgment, with appropriate allowance for transportation costs to
the Gulf Coast (or other appropriate location) to equilibrate such price to
the WTI Price. The WTI Price for any day which is not a trading day is the
WTI Price for the next preceding trading day.
Chargeable Costs
The "Chargeable Costs" per barrel of Royalty Production for each calendar
year are fixed amounts specified in the Conveyance and do not necessarily
represent the Company's actual costs of production. Chargeable Costs per
barrel for the five calendar years ended December 31, 1996 were: $6.00 during
1992; $6.75 during 1993; $8.00 during 1994; $8.25 during 1995; and $8.50
during 1996. Chargeable Costs for the calendar year ending December 31, 1997
and subsequent years are shown in the following table:
For the Chargeable For the Chargeable
Year Ending Costs Per Year Ending Costs Per
December 31 Barrel December 31 Barrel
------------ ---------- ------------ ----------
1997 $ 8.85 2009 $13.25
1998 9.30 2010 14.50
1999 9.80 2011 16.60
2000 10.00 2012 16.70
2001 10.75 2013 16.80
2002 11.25 2014 16.90
2003 11.75 2015 17.00
2004 12.00 2016 17.10
2005 12.25 2017 17.20
2006 12.50 2018 20.00
2007 12.75 2019 23.75
2008 13.00 2020 26.50
After 2020, Chargeable Costs increase at a uniform rate of $2.75 per
year.
Chargeable Costs may be reduced in future years by up to $1.20 per barrel
in the following circumstances:
(1) Chargeable Costs will be reduced by up to $1.20 per barrel in each
year from 2001 through 2005, inclusive, if, between January 1, 1996 and
December 31, 2000, an additional 200,000,000 stock tank barrels ("STB") of
proved reserves (before taking into account any production therefrom) have not
been added to the proved reserves allocated to the Subject Leases. For the
purpose of this calculation, additions to proved reserves include a credit
equal to the number of STB of proved reserves in excess of 100,000,000 added
to proved reserves after December 31, 1987 and before January 1, 1996.
8
(2) Chargeable Costs will be reduced by up to $ 1.20 per barrel in 2006
and subsequent years if, between January 1, 2001 and December 31, 2005, either
(a) an additional 400,000,000 STB of proved reserves (before taking into
account any production therefrom) have not been added to proved reserves
allocated to the Subject Leases (including, for the purpose of this
calculation, a credit equal to the number of STB of proved reserves in excess
of 300,000,000 added to the Company's reserves after December 31, 1987 and
before January 1, 2001), or (b) an additional 100,000,000 STB of proved
reserves (before taking into account any production therefrom) have not been
added to the reserves allocated to the Subject Leases, without allowing any
credit for additions prior to January 1, 2001. In general, "proved reserves"
for purposes of this determination consist of the Company's estimate
(determined to be reasonable by independent petroleum engineers) of the
quantities of crude oil and condensate that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years under
existing economic and operating conditions from the Prudhoe Bay (Permo-
Triassic Reservoir) in the Prudhoe Bay Unit. See "THE PRUDHOE BAY UNIT -
Reserve Estimates" below.
As of December 31, 1987, the proved reserves of crude oil and condensate
allocated to the Subject Leases were 2,035.6 million STB. Since that date,
the Company has made the additions (and deductions) to its estimates of proved
reserves allocated to the Subject Leases (before taking into account any
production from such additions) as shown in the following table:
Additions to Proved Reserves
Year ended ----------------------------
December 31 Annual Cumulative
----------- ------ ----------
(Million STB)
1988 42.3 42.3
1989 45.5 87.8
1990 24.0 111.8
1991 115.8 227.6
1992 144.3 371.9
1993 206.2 578.1
1994 89.9 668.0
1995 92.2 760.2
1996 (21.0) 739.2
The Company anticipates further additions in future years to the proved
reserves allocated to the Subject Leases. As of December 31, 1996, the
cumulative additions to the proved reserves allocated to the Subject Leases
were sufficient to prevent any reduction in Chargeable Costs during the years
2001 through 2005. However, downward revisions of proved reserve estimates in
1997 or subsequent years could result in a reduction of Chargeable Costs being
required as described above in the year 2001 or thereafter.
Cost Adjustment Factor
The "Cost Adjustment Factor" is the ratio of (1) the Consumer Price Index
published for the most recently past February, May, August or November, as the
case may be, to (2) 121.1 (the Consumer Price Index for January 1989), except
9
that (a) if for any calendar quarter the average WTI Price is $18.00 or less,
then the Cost Adjustment Factor for that quarter will be the Cost Adjustment
Factor for the immediately preceding quarter, and (b) the Cost Adjustment
Factor for any calendar quarter in which the average WTI Price exceeds $18.00,
after a calendar quarter during which the average WTI Price is equal to or
less than $ 18.00, and for each following calendar quarter in which the
average WTI Price is greater than $18.00, will be the product of (x) the Cost
Adjustment Factor for the most recently past calendar quarter in which the
average WTI Price is equal to or less than $18.00 and (y) a fraction, the
numerator of which will be the Consumer Price Index published for the most
recently past February, May, August or November, as the case may be, and the
denominator of which will be the Consumer Price Index published for the most
recently past February, May, August or November during a quarter in which the
average WTI Price is equal to or less than $18.00. The "Consumer Price Index"
is the U.S. Consumer Price Index, all items and all urban consumers, U.S. city
average, 1982-84 equals 100, as first published, without seasonal adjustment,
by the Bureau of Labor Statistics, Department of Labor, without regard to
subsequent revisions or corrections.
Production Taxes
"Production Taxes" are the sum of any severance taxes, excise taxes
(including windfall profit tax, if any), sales taxes, value added taxes or
other similar or direct taxes imposed upon the reserves or production,
delivery or sale of Royalty Production. Such taxes are computed at defined
statutory rates. In the case of taxes based upon wellhead or field value, the
Conveyance provides that the WTI Price less the product of $4.50 and the Cost
Adjustment factor will be deemed to be the wellhead or field value. At the
present time, the Production Taxes payable with respect to the Royalty
Production are the Alaska Oil and Gas Properties Production Tax ("Alaska
Production Tax") and the Alaska Oil and Gas Conservation Tax ("Alaska
Conservation Tax"). For the purposes of the Royalty Interest, the Alaska
Production Tax is computed without regard to the "economic limit factor," if
any, as the greater of the "percentage of value amount" (based on the
statutory rate and the wellhead value as defined above) and the "cents per
barrel amount." As of the date of this report, the statutory rate for the
purpose of calculating the "percentage of value amount" is 15 percent, 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. Due to the spill response
fund reaching $50 million in 1995, $0.02 per barrel of the surcharge has been
indefinitely suspended. In the event the balance of the spill response fund
falls below $50 million, the $0.02 per barrel surcharge will be reinstated
until the fund balance again reaches $50 million. The remaining $0.03 per
barrel surcharge is not affected by the fund's balance and will continue to be
imposed at all times.
Per Barrel Royalty Calculations
The following table shows how the above-described factors interacted
during each of the past five years to produce the Per Barrel Royalty paid for
each of the calendar quarters indicated.
10
Average Cost Adjusted Per
WTI Chargeable Adjustment Chargeable Production Barrel
Price Costs Factor Costs Taxes Royalty (a)
------- ---------- ---------- ---------- ---------- -----------
1992:
1st Qtr $18.94 $6.00 1.134 $ 6.80 $2.13 $10.00
2nd Qtr 21.20 6.00 1.143 6.86 2.46 11.88
3rd Qtr 21.67 6.00 1.153 6.92 2.53 12.23
4th Qtr 20.50 6.00 1.162 6.97 2.34 11.18
1993:
1st Qtr 19.85 6.75 1.171 7.90 2.24 9.71
2nd Qtr 19.76 6.75 1.180 7.96 2.22 9.57
3rd Qtr 17.77 6.75 1.180 7.96 1.92 7.88
4th Qtr 16.43 6.75 1.180 7.96 1.72 6.74
1994:
1st Qtr 14.80 8.00 1.180 9.44 1.48 3.88
2nd Qtr 17.79 8.00 1.180 9.44 1.93 6.42
3rd Qtr 18.49 8.00 1.192 9.53 2.02 6.93
4th Qtr 17.67 8.00 1.192 9.53 1.90 6.23
1995:
1st Qtr 18.35 8.25 1.200 9.90 2.00 6.45
2nd Qtr 19.32 8.25 1.212 10.00 2.11 7.21
3rd Qtr 17.87 8.25 1.212 10.00 1.90 5.98
4th Qtr 18.16 8.25 1.217 10.04 1.94 6.18
1996:
1st Qtr 19.74 8.50 1.227 10.43 2.17 7.14
2nd Qtr 21.70 8.50 1.241 10.55 2.45 8.70
3rd Qtr 22.36 8.50 1.247 10.59 2.55 9.22
4th Qtr 24.71 8.50 1.257 10.68 2.89 11.13
<FN>
- ---------------
(a) Per Barrel Royalty figures shown in this column are exact; but
subtracting the figures for Adjusted Chargeable Costs and Production Taxes
from the figures for Average WTI Prices in the columns to the left does not
yield the Per Barrel Royalty shown in all cases due to rounding.
Potential Conflicts of Interest
The interests of the Company and the Trust with respect to the Prudhoe
Bay Unit could at times be different. In particular, because the Per Barrel
Royalty is based on the WTI Price and Chargeable Costs rather than the
Company's actual price realized and actual costs, the actual per barrel profit
received by the Company on the Royalty Production could differ from the Per
Barrel Royalty to be paid to the Trust. It is possible, for example, that the
relationship between the Company's actual per barrel revenues and costs could
be such that the Company may determine to interrupt or discontinue production
in whole or in part even though a Per Barrel Royalty may otherwise have been
payable to the Trust pursuant to the Royalty Interest. This potential
11
conflict of interest could affect the royalties paid to Unit holders, although
the Company will be subject to the terms of the Prudhoe Bay Unit Operating
Agreement.
THE UNITS
Units
Each Unit represents an equal undivided share of beneficial interest in
the Trust. The Units do not represent an interest in or an obligation of the
Company, Standard Oil or any of their respective affiliates. Units are
evidenced by transferable certificates issued by the Trustee. Each Unit
entitles its holder to the same rights as the holder of any other Unit. The
Trust has no other authorized or outstanding class of equity securities.
Distributions of Income
The Company makes quarterly payments to the Trust of the amounts due with
respect to the Trust's Royalty Interest on the fifteenth day following the end
of each calendar quarter or, if the fifteenth is not a business day, on the
next succeeding business day (the "Quarterly Record Date"). The Trustee then
distributes an amount equal to the payment received from the Company (plus, if
applicable, any decrease in cash reserves previously established for estimated
liabilities and any other cash received by the Trustee), less the expenses and
payments of liabilities of the Trust (plus, if applicable, any net increase in
cash reserves for estimated liabilities) (the "Quarterly Distribution") to the
persons in whose names the Units were registered at the close of business on
the immediately preceding Quarterly Record Date.
A total of 8,040,000 Units were sold to the public in May 1989. Prior to
the public offering, however, 13,360,000 Units were sold in a private
placement to a number of institutional investors, including a number of
employee benefit plans subject to the requirements of the Employee Retirement
Income Security Act of 1974 ("ERISA"). The Trust Agreement, therefore,
contains a number of provisions intended to accommodate legal restrictions
resulting from the benefit plan status of these initial investors.
The Trust Agreement provides that unless certain conditions have been
satisfied or are applicable to the Trust, pending payment of the Quarterly
Distribution to the Unit holders, the Trustee must hold the money uninvested
in a non-interest bearing account. This requirement generally applies prior
to the date (the "Opinion Date") on which the Company has delivered to the
Trustee both (i) an opinion of nationally recognized ERISA counsel to the
effect that the Units have been registered under the Securities Exchange Act
of 1934, and the Units are both widely-held and freely transferable (within
the meaning of Department of Labor regulations), and (ii) either an individual
prohibited transaction exemption or an advisory opinion issued by the
Department of Labor, or an opinion of nationally recognized ERISA counsel
based on such a prohibited transaction exemption or advisory opinion, to the
Trustee, the Trust or the Company to the effect that after the date upon which
the requirements referred to in the opinion described in clause (i) have been
satisfied, the assets of the Trust shall not constitute plan assets with
respect to any employee benefit plan which became a Unit holder prior to the
date such requirements have been satisfied. To date, the Company has not
delivered the prohibited transaction exemption, advisory opinion or opinion of
12
ERISA counsel referred to in clause (ii) of the preceding sentence and,
consequently, the Opinion Date has not occurred.
The investment prohibition described in the preceding paragraph does not
apply, however, during an "Insignificant Investor Period," which is defined to
mean any period prior to the Opinion Date during which benefit plan investors
(within the meaning of Department of Labor regulations) do not own a
sufficient number of Units to cause their equity participation in the Trust to
be "significant" (i.e., benefit plan investors hold 25 percent or more of the
value of the Units). The Units, however, are predominantly held by their
owners indirectly in "street name" through brokers and nominees. (Over 96
percent of the Units were held through brokers and nominees at December 31,
1996). The Trustee thus is unable to determine, on the basis of the names of
the Unit holders registered as such on its books, whether or not Unit
ownership by benefit plan investors is "significant" within the contemplation
of the Trust Agreement. As a result of this uncertainty, to date the Trustee
has held moneys received from the Company uninvested pending their
distribution to Unit holders, and The Bank of New York has had the use of
those balances during such periods.
The Trust Agreement provides that, after the Opinion Date, or during an
Insignificant Investor Period prior to the Opinion Date, the Trustee shall
pay the Quarterly Distribution on the fifth day after the Trustee's receipt of
the amount to be paid by the Company on each Quarterly Record Date, and that
collected cash balances being held by the Trustee for distribution shall be
invested in obligations issued or unconditionally guaranteed by the United
States or any agency or instrumentality thereof and secured by the full faith
and credit of the United States ("Government Obligations") or, if Government
Obligations with a maturity date on the date of the distribution to Unit
holders are not available, in repurchase agreements with banks having capital,
surplus and undivided profits of $100,000,000 or more (which may include The
Bank of New York) secured by Government Obligations. If time does not permit
the Trustee to invest collected funds in investments of the type described in
the preceding sentence, the Trustee may invest such funds overnight in a time
deposit with a bank meeting the foregoing requirement (including The Bank of
New York).
As a result of the recent disposition of substantially all of their Units
by several of the original institutional investors in the Trust, each of which
had held in excess of five percent of the outstanding Units, the Trustee has
conducted an examination of its Unit holder records and other available
information and has concluded that, although the matter is not free from
doubt, it is more probable than not that an Insignificant Investor Period
under the Trust Agreement is in effect. The Trustee further has been advised
by its counsel that, under present circumstances, there are likely to be no
adverse consequences to any benefit plan investor, to the Trust, or to the
Trustee if the Trustee were to commence investing collected funds pending
their distribution to Unit holders in investments of the type permitted by the
Trust Agreement. The Trustee therefore intends to commence investing
collected funds as described above.
Reports to Unit Holders
Within 90 days after the end of each calendar year, the Trustee mails to
the holders of record of Units at any time during the calendar year a report
containing information to enable them to make the calculations necessary for
federal and Alaska income tax purposes, including the calculation of any
13
depletion or other deduction which may be available to them for the calendar
year. In addition, after the end of each calendar year the Trustee mails to
holders of Units an annual report containing audited financial statements of
the Trust, a letter of the independent petroleum engineers engaged by the
Trust setting forth a summary of such firm's determinations regarding the
Company's estimates of proved reserves and other related matters, and certain
other information required by the Trust Agreement.
Following the end of each quarter, the Trustee mails Unit holders a
quarterly report showing the assets and liabilities, receipts and
disbursements and income and expenses of the Trust and the Royalty Production
for such Quarter.
Limited Liability of Unit Holders
The Trust Agreement provides that the holders of Units are, to the full
extent permitted by Delaware law, entitled to the same limitation of personal
liability extended to stockholders of private corporations for profit under
Delaware law.
Possible Divestiture of Units
The Trust Agreement imposes no restrictions on nationality or other
status of the persons eligible to hold Units. However, the Trust Agreement
provides that if at any time the Trust or the Trustee is named a party in any
judicial or administrative proceeding seeking the cancellation or forfeiture
of any property in which the Trust has an interest because of the nationality,
or any other status, of any one or more holders, the following procedures will
be applicable:
(i) The Trustee will give written notice of the existence of such
proceedings to each holder whose nationality or other status is an issue in
the proceeding. The notice will contain a reasonable summary of such
proceeding and will constitute a demand to each such holder that he dispose of
his Units within 30 days to a party not of the nationality or other status at
issue in the proceeding described in the notice.
(ii) If any holder fails to dispose of his Units in accordance with such
notice, the Trustee will redeem, at any time during the 90-day period
following the termination of the 30-day period specified in the notice, any
Unit not so transferred for a cash price per Unit equal to the closing price
of the Units on the stock exchange on which the Units are then listed or, in
the absence of any such listing, the closing bid price on the NASDAQ National
Market System if the Units are so quoted or, if not, the mean between the
closing bid and asked prices for the Units in the over-the-counter market, in
either case as of the last business day prior to the expiration of the 30-day
period stated in the notice. If the Units are neither listed nor traded in
the over-the-counter market, the price will be the fair market value of the
Units as determined by a recognized firm of investment bankers or other
competent advisor or expert.
Units redeemed by the Trustee will be cancelled. The Trustee may, in its
sole discretion, cause the Trust to borrow any amount required to redeem the
Units. If the purchase of Units from an ineligible holder by the Trustee
would result in a non-exempt "prohibited transaction" under ERISA, or under
the Internal Revenue Code of 1986, the Units subject to the Trustee's right of
14
redemption will be purchased by the Company or a designee thereof, at the
above described purchase price.
Issuance of Additional Units
The Trust Agreement provides that the Company or an affiliate from time
to time may assign to the Trust additional royalty interests meeting certain
conditions, and, upon satisfaction of various other conditions, including
receipt by the Trustee of a ruling from the Internal Revenue Service to the
effect that neither the existence nor the exercise of the right to assign the
additional royalty interest or the power to accept such assignment will
adversely affect the classification of the Trust as a "grantor trust" for
federal income tax purposes, the Trust may issue up to an additional
18,600,000 Units, The Company has not conveyed any additional royalty
interests to the Trust, and the Trust has not issued any additional Units,
since the inception of the Trust.
THE BP SUPPORT AGREEMENT
BP has agreed pursuant to the terms of a Support Agreement, dated
February 28, 1989, among BP, the Company, Standard Oil and the Trust (the
"Support Agreement"), to provide financial support to the Company in meeting
its payment obligations under the Royalty Interest.
Within 30 days of notice to BP, BP will ensure that the Company is in a
position to perform its payment obligations under the Royalty Interest and to
satisfy its payment obligations to the Trust under the Trust Agreement,
including contributing to the Company such funds as are necessary to make such
payments. BP's obligations under the Support Agreement are unconditional and
directly enforceable by Unit holders.
Except as described below, no assignment, sale, transfer, conveyance,
mortgage or pledge or other disposition of the Royalty Interest will relieve
BP of its obligations under the Support Agreement.
Neither BP nor the Company may transfer or assign its rights or
obligations under the Support Agreement without the prior written consent of
the Trust, except that BP can arrange for its obligations under the Support
Agreement to be performed by any affiliate of BP, provided that BP remains
responsible for ensuring that such obligations are performed in a timely
manner.
The Company may sell or transfer all or part of its working interest in
the Prudhoe Bay Unit, although such a transfer will not relieve BP of its
responsibility to ensure that the Company's payment obligations with respect
to the Royalty Interest and under the Trust Agreement and the Conveyance are
performed.
BP will be released from its obligation under the Support Agreement upon
the sale or transfer of all or substantially all of the Company's working
interest in the Prudhoe Bay Unit if the transferee agrees to assume and be
bound by BP's obligation under the Support Agreement in a writing reasonably
satisfactory to the Trustee and if the transferee is an entity having a rating
assigned to outstanding unsecured, unsupported long term debt from Moody's
Investors Service, Inc. of at least A3 or from Standard & Poor's Rating
Services of at least A- or an equivalent rating from at least one nationally-
15
recognized statistical rating organization (after giving effect to the sale or
transfer to such entity of all or substantially all of the Company's working
interest in the Prudhoe Bay Unit and the assumption by such entity of all of
the Company's obligations under the Conveyance and of all BP's obligations
under the Support Agreement).
THE PRUDHOE BAY UNIT
General
The Prudhoe Bay field (the "Field") is located on the North Slope of
Alaska, 250 miles north of the Arctic Circle and 650 miles north of Anchorage.
The Field extends approximately 12 miles by 27 miles and contains nearly
150,000 productive acres. The Field, which was discovered in 1968 by BP and
others, has been in production since 1977. The Field is the largest producing
oil field in North America. As of December 31, 1996, approximately 9.6
billion STB of oil and condensate had been produced from the Field. Field
development is well advanced with approximately $17 billion gross capital
spent and a total of about 1,700 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 Prudhoe
Bay Unit was established to optimize Field development. The Prudhoe Bay Unit
Operating Agreement specifies the allocation of production and costs to
Prudhoe Bay Unit owners. 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 (Permo-Triassic) Reservoir, and does not pertain to the
Lisburne and Endicott formations.
The Ivishak sandstone was deposited, commencing some 250 million years
ago, during the Permian and Triassic geologic periods. The sediments in the
Ivishak are composed of sandstones, conglomerate and shales which were
deposited by a massive braided river and delta system that flowed from an
ancient mountain system to the north. Oil was trapped in the Ivishak by a
combination of structural and stratigraphic trapping mechanisms.
Gross reservoir thickness is 550 feet, with a maximum oil column
thickness of 425 feet. The original oil column is bounded on the top by a
gas-oil contact, originally at 8,575 feet below sea level across the main
field, and on the bottom by an oil-water contact at approximately 9,000 feet
below sea level. A layer of heavy oil and tar overlays the oil-water contact
in the main field and has an average thickness of around 40 feet.
16
Oil Characteristics
The produced oil from the reservoir is a medium grade, low sulfur crude
with an average specific gravity of 27 degrees API. The gas cap composition
is such that, upon surfacing, a liquid hydrocarbon phase, known as condensate,
is formed.
The interests of the Unit holders are based upon oil produced from the
oil rim and condensate produced from the gas cap, but not upon gas production
(which is currently uneconomic) or natural gas liquids production stripped
from gas produced.
Prudhoe Bay Unit Operation and Ownership
Since several companies hold acreage within the Field's limits, a unit
was established to ensure optimum development of the Field. The Prudhoe Bay
Unit, which became effective on April 1, 1977, divided the Field into two
operating areas. The Company is the operator of the Western Operating Area
and Arco Alaska Inc. is the operator of the Eastern Operating Area. Oil and
condensate production comes from both the Western Operating Area and the
Eastern Operating Area.
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. Effective December 31, 1995, the Company
acquired the interest of Amerada Hess Corporation of 0.5379191 percent on the
oil rim participating area. Under the terms of the Conveyance, this increase
in the Company's participation is not allocated to the Subject Leases and does
not increase the Trust's Royalty Interest.
The ownership of the Prudhoe Bay Unit by participating area as of
December 31, 1996 is summarized in the following table:
Oil Rim Gas Cap
------- -------
BP 51.22% (a) 13.84%
Arco 21.87 42.56
Exxon 21.87 42.56
Mobil/Phillips/Chevron 4.44 1.04
Others 0.60 0.00
------- -------
Total 100.00% 100.00%
======= =======
<FN>
- ---------------
(a) The Trust's share of oil production is computed based on BP's
ownership interest of 50.68 percent as of February 28, 1989.
17
Historical Production
Production began on June 19, 1977, with the completion of the Trans
Alaska Pipeline System. The pipeline has a capacity of 1.5 million barrels of
oil per day.
As of December 31, 1996, there were about 1,079 producing oil wells, 36
gas reinjection wells, 42 water injection wells and 140 water and miscible gas
injection wells in the Field. In terms of individual well performance, oil
production rates range from 60 to 5,000 barrels of oil per day. Currently,
the average well production rate is about 788 barrels of oil per day.
The Company's share of the hydrocarbon liquids production from the Field
includes oil, condensate and natural gas liquids. Using the production
allocation procedures from the Prudhoe Bay Unit Operating Agreement, the
Field's production and the share of oil and condensate (net of State of Alaska
royalty) allocated to the Subject Leases have been as follow during the
periods indicated:
Oil Condensate
Year -------------------------- -------------------------
Ended Total Subject Total Subject
December 31 Field Leases Field Leases
----------- ----------- ---------- ---------- ----------
(Million STB per day)
1992 1,050.5 465.9 131.4 15.9
1993 906.8 402.2 150.0 18.2
1994 785.5 348.4 177.5 21.5
1995 659.3 292.4 200.0 24.2
1996 583.1 258.6 187.6 22.7
The Company estimates that production will decline at an average rate of
approximately 10 percent per year for the next three to five years, and that
the rate of decline will decrease to approximately five percent per year by
the year 2030.
Transportation of Prudhoe Bay Oil
Production from the Field is carried to Pump Station 1, which is the
starting point for the Trans Alaska Pipeline System, through two 34-inch
diameter transit lines, one from each half of the Field. At Pump Station 1,
Alyeska Pipeline Service Company, the pipeline operator, meters the oil and
pumps it south to Valdez where it is either loaded onto marine tankers or
stored temporarily. It takes the oil about six days to make the trip in the
48-inch diameter pipeline.
Various protests of the Trans Alaska Pipeline System tariffs have been
filed by, among others, the State of Alaska over a period of several years.
Proceedings to resolve these protests are ongoing in the Federal Energy
Regulatory Commission, the Alaska Public Utilities Commission and a Court of
Appeal.
18
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 affected by each of
these recovery processes.
Reserve Estimates
The Company's net proved remaining reserves of oil and condensate in the
Prudhoe Bay Unit as of December 31, 1996 were estimated to be approximately
1,247 million barrels. This current estimate of reserves is based upon
various assumptions, including a reasonable estimate of the allocation of
hydrocarbon liquids between oil and condensate pursuant to the procedures of
the Prudhoe Bay Unit Operating Agreement. Estimates of proved reserves are
inherently imprecise and subjective and are revised over time as additional
data becomes available. Such revisions may often be substantial. The
Company anticipates that net production from current proved reserves allocated
to the Subject Leases will exceed 90,000 barrels per day until the year 2009.
The occurrence of major gas sales could accelerate the time at which the
Company's net production would fall below 90,000 barrels per day, due to the
consequent decline in reservoir pressure. The Company also projects continued
economic production thereafter, at a declining rate, until the year 2030;
however, on the basis of the economic conditions and reserve estimates as of
December 31, 1996, the Per Barrel Royalty will be zero after the year 2017.
The Company's reserve estimates and production assumptions and
projections are predicated upon a reasonable estimate of hydrocarbon
allocation between oil and condensate. Oil and condensate are physically
produced in a commingled stream of hydrocarbon liquids. The allocation of
hydrocarbon liquids between the oil and condensate from the Field is a
theoretical calculation performed in accordance with procedures specified in
the Prudhoe Bay Unit Operating Agreement. Due to the differences in
percentages between oil and condensate, the overall share of oil and
condensate production allocated to the Subject Leases will vary over time
according to the proportions of hydrocarbon liquid being allocated as
condensate or as oil under the Prudhoe Bay Unit Operating Agreement allocation
procedures. Under the terms of an Issues Resolution Agreement entered into by
the Prudhoe Bay Unit owners in October 1990, the allocation procedures have
been adjusted to generally allocate condensate in a manner which approximates
the anticipated decline in the production of oil until an agreed original
condensate reserve of 1.175 billion barrels has been allocated to the working
interest owners.
The reserves attributable to the Trust's Royalty Interest constitute only
a part of the overall reserves allocated to the Subject Leases. The Company
has estimated that the net remaining proved reserves attributable to the Trust
as of December 31, 1996 were 111.1 million barrels of oil and condensate, of
which 102.0 million barrels were proved developed reserves and 9.1 million
barrels were proved undeveloped reserves. Using procedures specified in
Financial Accounting Standards Board Statement of Financial Standards No. 69,
19
the Company calculated that as of December 31, 1996 production of oil and
condensate from the proved reserves allocated to the Trust will result in
estimated future net revenues to the Trust of $780 million, with a present
value of $412 million. The Company's estimates of proved reserves and the
estimated future net revenues from the Prudhoe Bay Unit have been reviewed by
Miller and Lents, Ltd., independent oil and gas consultants, as set forth in
their report following this section.
There is no precise method of 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 are estimated by allocating to the Trust its
share of estimated future production from the Field, based on WTI Prices.
The following table shows the net remaining proved reserves of oil and
condensate allocated to the Subject Leases, the net proved reserves allocated
to the Trust, and the WTI Prices on the dates indicated:
Net Proved Reserves
------------------------------- WTI Prices
December 31 Subject Leases(a) Trust(b) Per Barrel
- ----------- ----------------- -------- ----------
(Million STB)
1992 1,387.9 94.3 $19.50
1993 1,439.9 43.2 14.15
1994 1,395.0 81.0 17.75
1995 1,371.4 81.0 19.58
1996 1,247.0 111.1 25.93
<FN>
- ---------------
(a) Includes proved undeveloped reserves of 448.9 million STB at
December 31, 1992; 243.1 million STB at December 31, 1993; 211.0 million STB
at December 31, 1994; 275.2 million STB at December 31, 1995; and 223.4
million STB at December 31, 1996.
(b) Includes proved undeveloped reserves of 14.9 million STB at December
31, 1992; 0 STB at December 31, 1993 and 1994; 0.8 million STB at December 31,
1995; and 9.1 million STB at December 31, 1996.
The reserve volumes attributable to the Trust are estimated using an
allocation of reserve volumes based on estimated future production and the
current WTI Price, and assume no future movement in the Consumer Price Index
and no future additions by the Company of proved reserves. The estimated
reserve volumes attributable to the Trust will vary if different estimates of
production, prices and other factors are used. Even if expected reservoir
performance does not change, the estimated reserves, economic life, and future
revenues attributable to the Trust may change significantly in the future.
This may result from changes in the WTI Price or from changes in other
prescribed variables utilized in calculations defined by the Overriding
Royalty Conveyance. See Note 5 of the Notes to Financial Statements in
Item 8.
20
The Company is under no obligation to make investments in development
projects which would add additional non-proved resources to proved reserves
and cannot make such investments without the concurrence of the Prudhoe Bay
Unit working interest owners. However, several such investments which would
augment Prudhoe Bay projects are already in 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 Prudhoe Bay Unit working
interest owners will make any such investments they do regularly assess the
technical and economic attractiveness of implementing further projects to
increase Prudhoe Bay Unit proved reserves.
In the event of changes in the Company's current assumptions, oil and
condensate recoveries may be reduced from the current estimates, unless
recovery projects other than those included in the current estimates are
implemented.
21
INDEPENDENT OIL AND GAS CONSULTANTS' REPORT
MILLER AND LENTS, LTD. MARTIN G. MILLER (1948-1980)
OIL AND GAS CONSULTANTS MAX R LENTS
TWENTY-SEVENTH FLOOR KENNETH B. FORD
1100 LOUISIANA P. G . VON TUNGELN
HOUSTON, TEXAS 77002-5216 JAMES C. PEARSON
S. J. STIEBER
TELEPHONE 713 651-9455 T. LESLIE REEVES
TELEFAX 713 654-9914 LARRY M. GRING
JAMES A. COLE
February 14, 1997 K. R. CHEATHAM
J. L. POWELL
WILLIAM P KOZA
CHARLES G. GUFFEY
WILLIAM K. KIBLER
KAREN F. LOVING
CHRISTOPHER A. BUTTA
GREGORY W. ARMES
GARY B. KNAPP
LUCY B. KING
CARL T. DISMUKE
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, 1996
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, 1996. 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 7, 1997, 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
22
production profiles, and (6) pertinent provisions of the Prudhoe Bay Unit
Operating Agreement, the Issues Resolution Agreement, the Overriding Royalty
Conveyance, the Trust Conveyance, the BP Prudhoe Bay Royalty Trust Agreement,
and other related documents referenced in the Form F-3 Registration Statement
filed with the Securities and Exchange Commission on August 7, 1989, by BP
Exploration (Alaska) Inc.
Proved Reserves were estimated by BP Exploration (Alaska) Inc. in
accordance with the definitions contained in Securities and Exchange
Commission Regulation S-X, Rule 4-10(a). Estimated Future Net Revenues and
Present Value of Estimated Future Net Revenues are not intended and should not
be interpreted to represent fair market values for the estimated reserves.
The Prudhoe Bay (Permo-Triassic) Reservoir is defined in the Prudhoe Bay
Unit Operating Agreement. The Prudhoe Bay Unit is an oil and gas unit
situated on the North Slope of Alaska. The BP Prudhoe Bay Royalty Trust is
entitled to a royalty payment on 16.4246 percent of the first 90,000 barrels
of the actual average daily net production of oil and condensate for each
calendar quarter from the BP Exploration (Alaska) Inc. working interest as
defined in the Overriding Royalty Conveyance. The payment amount depends upon
the Per Barrel Royalty which in turn depends upon the West Texas Intermediate
Price, the Chargeable Costs, the Cost Adjustment Factor, and Production Taxes,
all of which are defined in the Overriding Royalty Conveyance. "Barrel" as
used herein means Stock Tank Barrel as defined in the Overriding Royalty
Conveyance.
Our reviews do not constitute independent estimates of the reserves and
annual production rate forecasts for the areas, pay zones, projects, and
recovery processes examined. We relied upon the accuracy and completeness of
information provided by BP Exploration (Alaska) Inc. with respect to pertinent
ownership interests and various other historical, accounting, engineering, and
geological data.
As a result of our cumulative reviews, based on the foregoing, we conclude
that:
1. A large body of basic data and detailed analyses are available and
were used in making the estimates. In our judgment, the quantity and
quality of currently available data on reservoir boundaries, original
fluid contacts, and reservoir rock and fluid properties are sufficient
to indicate that any future revisions to the estimates of total
original in-place volumes should be minor. Furthermore, the data and
analyses on recovery factors and future production rates are
sufficient to support the Proved Reserves estimates.
2. The methods and procedures employed to accumulate and evaluate the
necessary information and to estimate, document, and reconcile
reserves, annual production rate forecasts, and future net revenues
are effective and are in accordance with generally accepted geological
and engineering practice in the petroleum industry.
3. Based on our limited independent tests of the computations of
reserves, production flowstreams, and future net revenues, such
computations were performed in accordance with the methods and
procedures described to us.
4. The estimated net remaining Proved Reserves attributable to the BP
Prudhoe Bay Royalty Trust as of December 31, 1996, of 111.1 million
23
barrels of oil and condensate are, in the aggregate, reasonable. Of
the 111.1 million barrels of total Proved Reserves, 102.0 million
barrels are Proved Developed Reserves, and 9.1 million barrels are
Proved Undeveloped Reserves.
5. Utilizing the specified procedures outlined in Financial Accounting
Standards Board Statement of Financial Accounting Standards No. 69, BP
Exploration (Alaska) Inc. calculated that as of December 31, 1996,
production of the Proved Reserves will result in Estimated Future Net
Revenues of $780 million and Present Value of Estimated Future Net
Revenues of $412 million to the BP Prudhoe Bay Royalty Trust. These
estimates are reasonable.
6. BP Exploration (Alaska) Inc. estimated that, as of December 31, 1996,
739.2 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 2009 is
reasonable. As long as the Per Barrel Royalty has a positive value,
average daily production attributable to the BP Prudhoe Bay Royalty
Trust will remain constant until the net production falls below 90,000
barrels per day; thereafter, production attributable to the BP Prudhoe
Bay Royalty Trust will decline with the BP Exploration (Alaska) Inc.
production. However, the Per Barrel Royalty will not have a positive
value if the West Texas Intermediate Price is less than the sum of the
per barrel Chargeable Costs and per barrel Production Taxes,
appropriately adjusted in accordance with the Overriding Royalty
Conveyance. Under such circumstances, average daily production
attributable to the BP Prudhoe Bay Royalty Trust will have no value
and therefore will not contribute to the reserves regardless of BP
Exploration (Alaska) Inc.'s net production level.
8. Based on the West Texas Intermediate Price of $25.93 per barrel on
December 31, 1996, current Production Taxes, and the Chargeable Costs
adjusted as prescribed by the Overriding Royalty Conveyance, the
projection that royalty payments will continue through the year 2017
is reasonable. BP Exploration (Alaska) Inc. expects continued
economic production at a declining rate through the year 2030;
however, for the economic conditions and production forecast as of
December 31, 1996, the Per Barrel Royalty will be zero following the
year 2017. Therefore, no reserves are currently attributed to the BP
Prudhoe Bay Royalty Trust after that date.
9. Even if expected reservoir performance does not change, the estimated
reserves, economic life, and future revenues attributable to the BP
Prudhoe Bay Royalty Trust may change significantly in the future.
This may result from changes in the West Texas Intermediate Price or
from changes in other prescribed variables utilized in calculations
defined by the Overriding Royalty Conveyance.
24
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 the decline in gross oil and
condensate production capacity.
In making its future production rate forecasts, BP Exploration (Alaska)
Inc. provided for normal downtime and planned facilities upsets. Although
allowances for unplanned upsets are also considered in the estimates, the
studies do not provide for any impediments to crude oil production as a
consequence of major disruptions.
Under current economic conditions, gas from the Alaskan North Slope,
except for minor volumes, cannot be marketed commercially. Oil and condensate
recoveries are expected to be greater as a result of continued reinjection of
produced gas than the recoveries would be if major volumes of produced gas
were being sold. No major gas sale is assumed in the current estimates. If
major gas sales are determined to be economically viable in the future, BP
Exploration (Alaska) Inc. estimates that such sales would not actually
commence until 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.
25
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 BP Exploration
(Alaska) Inc. or the BP Prudhoe Bay Royalty Trust that would affect our
objectivity.
Very truly yours,
MILLER AND LENTS, LTD.
[STATE OF TEXAS
By /s/ William P. Koza *
---------------------- WILLIAM P. KOZA
William P. Koza 58894
Vice President REGISTERED
WPK/hsd PROFESSIONAL
ENGINEER]
26
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
the Organization of Petroleum Exporting Countries can particularly affect
world oil supply and oil prices.
CERTAIN TAX CONSIDERATIONS
The following is a summary of the principal tax consequences to Unit
holders resulting from the ownership and disposition of Units. The laws and
regulations affecting these matters are complex, and are subject to change by
future legislation or regulations or new interpretations by the Internal
Revenue Service, state taxing authorities or the courts. In addition, there
may be differences of opinion as to the applicability or interpretation of
present tax laws and regulations. The Company and the Trust have not requested
any rulings from the Internal Revenue Service with respect to the tax
treatment of the Units, and no assurance can be given that the Internal
Revenue Service would concur with the statements below.
Unit holders are urged to consult their tax advisors regarding the
effects on their specific tax situations of owning and disposing of Units.
Federal Income Tax
Classification of the Trust
The following discussion assumes that the Trust is properly classified as
a grantor trust under current law and is not an association taxable as a
corporation.
General Features of Grantor Trust Taxation
A grantor trust is not subject to tax, and its beneficiaries (the Unit
holders in the case of the Trust) are considered for tax purposes to own the
27
assets of the trust directly. The Trust pays no federal income tax but files
an information return reporting all items of income or deduction. If a court
were to hold that the Trust is an association taxable as a corporation, the
Trust would incur substantial income tax liabilities in addition to its other
expenses.
Taxation of Unit Holders
In computing his federal income tax liability, each Unit holder is
required to take into account his share of all items of Trust income, gain,
loss, deduction, credit and tax preference, based on the Unit holder s method
of accounting. Consequently, it is possible that in any year a Unit holder s
share of the taxable income of the Trust may exceed the cash actually
distributed to him in that year. For example, if the Trustee should establish
a reserve or borrow money to satisfy debts and liabilities of the Trust income
used to establish the reserve or to repay the loan must be reported by the
Unit holder, even though the income is not distributed to the Unit holder.
The Trust makes quarterly distributions to Unit holders of record on each
Quarterly Record Date. The terms of the Trust Agreement seek to assure to the
extent practicable that income, expenses and deductions attributable to each
distributions are reportable by the Unit holder who receives the distribution.
The Trust allocates income and deductions to Unit holders based on record
ownership at Quarterly Record Dates. It is not known whether the Internal
Revenue Service will accept the allocation based on this method.
Depletion Deductions
The owner of an economic interest in producing oil and gas properties is
entitled to deduct an allowance for the greater of cost depletion or (if
otherwise allowable) percentage depletion on each such property. A Unit
holder's deduction for cost depletion in any year is calculated by multiplying
the holder's adjusted tax basis in his Units (generally his cost less prior
depletion deductions) by Royalty Production during the year and dividing that
product by the sum of Royalty Production during the year and estimated
remaining Royalty Production as of the end of the year. The allowance for
percentage depletion generally does not apply to interests in proven oil and
gas properties that were transferred after December 31, 1974 and prior to
October 12, 1990. The Omnibus Budget Reconciliation Act of 1990 repealed this
rule for transfers occurring on or after October 12, 1990. Unit holders who
acquired their Units on or after that date may be permitted to deduct an
allowance for percentage depletion if such deduction would otherwise exceed
the allowable deduction for cost depletion. In order to take percentage
depletion, a Unit holder must qualify for the independent producer exemption
contained in section 613A(c) of the Internal Revenue Code of 1986. Percentage
depletion is based on the Unit holder s gross income from the Trust rather
than on his adjusted basis in his Units. Any deduction for cost depletion or
percentage depletion allowable to a Unit holder reduces his adjusted basis in
his Units for purposes of computing subsequent depletion or gain or loss on
any subsequent disposition of Units.
Unit holders must maintain records of their adjusted basis in their
Units, make adjustments for depletion deductions to such basis, and use the
adjusted basis for the computation of gain or loss on the disposition of the
Units.
28
Taxation of Foreign Unit Holders
Generally, a holder of Units who is a nonresident alien individual or
which is a foreign corporation (a Foreign Taxpayer ) is subject to tax of on
the gross income produced by the Royalty Interest at a rate equal to 30
percent (or at a lower treaty rate, if applicable). This tax is withheld by
the Trustee and remitted directly to the United States Treasury. A Foreign
Taxpayer may elect to treat the income from the Royalty Interest as
effectively connected with the conduct of a United States trade or business
under Internal Revenue Code section 871 or section 882, or pursuant to any
similar provisions of applicable treaties. If a Foreign Taxpayer makes this
election, it is entitled to claim all deductions with respect to such income,
but a United States federal income tax return must be filed to claim such
deductions. This election once made is irrevocable unless an applicable
treaty allows the election to be made annually.
Section 897 of the Internal Revenue Code and the Treasury Regulations
thereunder treat the Trust as if it were a United States real property holding
corporation. Foreign holders owning more than five percent of the
outstanding Units are subject to United States federal income tax on the gain
on the disposition of their Units. Foreign Unit holders owning less than five
percent of the outstanding Units are not subject to United States federal
income tax on the gain on the disposition of their Units, unless they have
elected under Internal Revenue Code section 871 or section 872 to treat the
income from the Royalty Interest as effectively connected with the conduct of
a United States trade or business.
If a Foreign person is a corporation which made an election under
Internal Revenue Code section 882(d), the corporation would also be subject to
a 30 percent tax under Internal Revenue Code section 884. This tax is imposed
on U.S. branch profits of a foreign corporation that are not reinvested in the
U.S. trade or business. This tax is in addition to the tax on effectively
connected income. The branch profits tax may be either reduced or eliminated
by treaty.
Sale of Units
Generally, a Unit holder will realize gain or loss on the sale or
exchange of his Units measured by the difference between the amount realized
on the sale or exchange and his adjusted basis for such Units. Gain on the
sale of Units by a holder that is not a dealer with respect to such Units will
generally be treated as capital gain. However, pursuant to Internal Revenue
Code section 1254, certain depletion deductions claimed with respect to the
Units must be recaptured as ordinary income upon sale or disposition of such
interest.
Backup Withholding
A payor must withhold 31 percent of any reportable payment if the payee
fails to furnish his taxpayer identification number ("TIN") to the payor in
the required manner or if the Secretary of the Treasury notifies the payor
that the TIN furnished by the payee is incorrect. Unit holders will avoid
backup withholding by furnishing their correct TINs to the Trustee in the form
required by law.
29
State Income Taxes
Unit holders may be required to report their share of income from the
Trust to their state of residence or commercial domicile. However, only
corporate Unit holders will need to report their share of income to the State
of Alaska. Alaska does not impose an income tax on individuals or estates and
trusts. All Trust income is Alaska source income to corporate Unit holders and
should be reported accordingly.
ITEM 2. PROPERTIES
Reference is made to Item 1 for the information required by this item.
ITEM 3. LEGAL PROCEEDINGS
Not applicable.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS
Not applicable.
30
PART II
ITEM 5. MARKET FOR THE UNITS AND RELATED UNIT HOLDER MATTERS
The Units are listed on the New York Stock Exchange (ticker symbol BPT).
The following table shows the high and low sales prices of the Units in New
York Stock Exchange composite transactions, and the cash distributions per
Unit, for each calendar quarter in the two years ended December 31, 1996.
Distributions
High Low Per Unit
------- ------- -------------
1995:
- -----
First Quarter $18 $15 7/8 $0.389
Second Quarter 19 16 3/8 0.445
Third Quarter 17 1/8 15 5/8 0.375
Fourth Quarter 16 1/4 13 0.386
1996:
- -----
First Quarter 16 1/2 14 3/8 0.439
Second Quarter 17 14 1/4 0.533
Third Quarter 17 3/4 14 7/8 0.582
Fourth Quarter 17 7/8 16 1/4 0.702
As of March 25, 1997, 21,400,000 Units outstanding and were held by 1,338
holders of record.
Future payments of cash distributions are dependent on such factors as
the prevailing WTI Price, the relationship of the rate of change in the WTI
Price to the rate of change in the Consumer Price Index, the Chargeable Costs,
the rates of Production Taxes prevailing from time to time, and the actual
production from the Prudhoe Bay Unit.
31
ITEM 6. SELECTED FINANCIAL DATA
The following table presents in summary form selected financial information
regarding the Trust.
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
(In thousands, except per Unit amounts)
Royalty revenues $ 42,263 $ 34,886 $ 32,401 $ 51,727 $ 65,250
Trust administration
expenses 750 688 658 554 413
---------- ---------- ---------- ---------- ----------
Cash earnings $ 41,513 $ 34,198 $ 31,743 $ 51,173 $ 64,837
========== ========== ========== ========== ==========
Cash distributions $ 41,513 $ 34,198 $ 31,743 $ 51,173 $ 64,837
========== ========== ========== ========== ==========
Cash distributions
per unit $ 1.940 $ 1.598 $ 1.483 $ 2.391 $ 3.030
========== ========== ========== ========== ==========
Units outstanding 21,400,000 21,400,000 21,400,000 21,400,000 21,400,000
========== ========== ========== ========== ==========
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Liquidity and Capital Resources
The Trust is a passive entity, and the Trustee's activities are limited
to collecting and distributing the revenues from the Royalty Interest and
paying liabilities and expenses of the Trust. The Trust has no source of
liquidity and no capital resources other than the revenue attributable to the
Royalty Interest that it receives from time to time. See generally the
discussion under "THE ROYALTY INTEREST" in Item 1 for a description of the
calculation of the Per Barrel Royalty, and the discussion under "THE PRUDHOE
BAY UNIT - Reserve Estimates" and "INDEPENDENT OIL AND GAS CONSULTANTS'
REPORT" in Item 1 for information concerning the estimated future net revenues
of the Trust.
Results of Operations
Royalty revenues are generally received on the Quarterly Record Date
(generally the fifteenth day of the month) following the end of the calendar
quarter in which the related Royalty Production occurred. The Trustee, to the
extent possible, pays all expenses of the Trust for each quarter on the
Quarterly Record Date on which the revenues for the quarter are received.
Both revenues and Trust expenses are recorded on a cash basis and, as a
result, distributions to Unit holders in the years ended December 31, 1996,
1995 and 1994 are attributable to the Company's operations during the twelve-
month periods ended September 30, 1996, 1995 and 1994, respectively.
32
As long as the Company's average daily net production from the Prudhoe
Bay Unit exceeds 90,000 barrels, which the Company currently projects will
continue until the year 2009, the only factors affecting the Trust's revenues
and distributions to Unit holders are changes in WTI Prices, scheduled annual
increases in Chargeable Costs, changes in the Consumer Price Index, changes in
Production Taxes and changes in the expenses of the Trust.
1995 compared to 1994
Both royalty revenues and cash distributions increased by approximately
7.7 percent from 1994 to 1995, reflecting generally higher WTI Prices during
1995 which were not fully offset by relatively modest increases in Adjusted
Chargeable Costs and Production Taxes. See "THE ROYALTY INTEREST - Per Barrel
Royalty Calculations" in Item 1. Although trust administration expenses
increased by approximately 4.6 percent, from $658,000 in 1994 to $688,000 in
1995, they remained constant in relation to royalty revenues, at approximately
2 percent in each of 1994 and 1995.
1996 compared to 1995
Royalty revenues and cash distributions increased by approximately 21.2%
and 21.4%, respectively, from 1995 to 1996, reflecting continued increases in
WTI Prices that outpaced increases in Adjusted Chargeable Costs and Production
Taxes. Trust administration expenses increased by 9.0% from 1995 to 1996, but
fell to 1.8% in relation to royalty revenues in 1996.
33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BP PRUDHOE BAY ROYALTY TRUST
INDEX TO FINANCIAL STATEMENTS
Page
----
Independent Auditors' Report 34
Statement of Assets, Liabilities and Trust Corpus
As of December 31, 1996 and 1995 35
Statements of Cash Earnings and Distributions for
the years ended December 31, 1996, 1995 and 1994 36
Statements of Changes in Trust Corpus for the years
ended December 31, 1996, 1995 and 1994 37
Notes to Financial Statements 38
34
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, 1996 and 1995,
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,
1996. 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, 1996 and 1995, 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, 1996, on the basis of
accounting described in note 2.
KPMG Peat Marwick LLP
New York, New York
March 27, 1997
35
BP PRUDHOE BAY ROYALTY TRUST
Statements of Assets, Liabilities and Trust Corpus
December 31, 1996 and 1995
(In thousands, except unit data)
Assets 1996 1995
---- ----
Royalty Interest (notes 1 and 2) $ 535,000 535,000
Less: accumulated amortization (265,970) (230,330)
--------- ---------
Total assets $ 269,030 304,670
========= =========
Liabilities and Trust Corpus
Accrued expenses $ 90 126
Trust Corpus (40,000,000 units of beneficial
interest authorized, 21,400,000 units issued
and outstanding) 268,940 304,544
--------- ---------
Total liabilities and Trust Corpus $ 269,030 304,670
========= =========
<FN>
See accompanying notes to financial statements.
36
BP PRUDHOE BAY ROYALTY TRUST
Statements of Cash Earnings and Distributions
For the Years Ended December 31, 1996, 1995 and 1994
(In thousands, except unit data)
1996 1995 1994
---- ---- ----
Royalty revenues $ 42,263 34,886 32,401
Trust administrative expenses 750 688 658
---------- ---------- ----------
Cash earnings $ 41,513 34,198 31,743
========== ========== ==========
Cash distributions $ 41,513 34,198 31,743
========== ========== ==========
Cash distributions per unit $ 1.940 1.598 1.483
========== ========== ==========
Units outstanding 21,400,000 21,400,000 21,400,000
========== ========== ==========
<FN>
See accompanying notes to financial statements.
37
BP PRUDHOE BAY ROYALTY TRUST
Statements of Changes in Trust Corpus
For the Years Ended December 31, 1996, 1995 and 1994
(In thousands)
1995 1995 1994
---- ---- ----
Trust Corpus at beginning of year $ 304,544 340,193 407,057
Cash earnings 41,513 34,198 31,743
Decrease (increase) in
accrued Trust expenses 36 (8) (34)
Cash distributions (41,513) (34,198) (31,743)
Amortization of Royalty Interest (35,640) (35,641) (66,830)
---------- -------- --------
Trust Corpus at end of year $ 268,940 304,544 340,193
========== ======== ========
<FN>
See accompanying notes to financial statements.
38
BP PRUDHOE BAY ROYALTY TRUST
Notes to Financial Statements
December 31, 1996, 1995 and 1994
(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") as of
February 28, 1989, located on the North Slope of Alaska. Trust Unit
holders will remain subject at all times to the risk that production will
be interrupted or discontinued or fall, on average, below 90,000 barrels
per day in any quarter. BP has guaranteed the performance by the Company
of its payment obligations with respect to the Royalty Interest.
The 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). For
years subsequent to 2001, Chargeable Costs will be reduced up to a
maximum amount of $1.20 per barrel in each year if additions to the
Field's proved reserved 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
39
Trust and distributed to Trust Unit holders, net of Trust expenses, in
the month succeeding the end of each calendar quarter. The Trust will
terminate upon the first to occur of the following events:
(a) On or prior to December 31, 2010: upon a vote of Trust Unit holders
of not less than 70% of the outstanding Trust Units.
(b) After December 31, 2010: (i) upon a vote of Trust Unit holders of
not less than 60% of the outstanding Trust Units, or (ii) at such
time the net revenues from the Royalty Interest for two successive
years commencing after 2010 are less than $1,000,000 per year
(unless the net revenues during such period are materially and
adversely affected by certain events).
(2) BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on a modified
cash basis and reflect the Trust's assets, liabilities and Trust Corpus
and the earnings and distributions as follows:
(a) Revenues are recorded when received (generally within 15 days of the
end of the preceding quarter) and distributions to Trust Unit
holders are recorded when paid.
(b) Trust expenses (which include accounting, engineering, legal, and
other professional fees, trustees' fees and out-of-pocket expenses)
are recorded when incurred.
(c) Amortization of the Royalty Interest is calculated based on the
units of production attributable to the Trust over the production of
estimated proved reserves attributable to the Trust at the beginning
of the fiscal year (approximately 80,991,000, 80,991,000 and
43,193,000 barrels of estimated proved reserves were used to
calculate the amortization of the Royalty Interest for the years
ended December 31, 1996, 1995 and 1994, respectively). Such
amortization is charged directly to the Trust Corpus, and does not
affect cash earnings. The rate for amortization per net equivalent
barrel of oil was $6.61, $6.61 and $12.39 for the years ended
December 31, 1996, 1995 and 1994, respectively. The remaining
unamortized balance of the net overriding Royalty Interest at
December 31, 1996 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.
40
Estimates and assumptions are required to be made regarding assets,
liabilities and changes in Trust Corpus resulting from operations when
financial statements are prepared. Changes in the economic environment,
financial markets and any other parameters used in determining these
estimates could cause actual results to differ.
(3) 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.
(4) SUMMARY OF QUARTERLY RESULTS (UNAUDITED)
A summary of selected quarterly financial information for the years
ended December 31, 1996 and 1995 is as follows (in thousands, except unit
data):
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
------- ------- ------- -------
1996
Royalty revenues $8,411 9,610 11,701 12,541
Trust administrative expenses 151 213 299 87
------ ------ ------ ------
Cash earnings 8,260 9,397 11,402 12,454
Cash distributions 8,260 9,397 11,402 12,454
Cash distributions per unit 0.386 0.439 0.533 0.582
1995
Royalty revenues $8,478 8,584 9,698 8,126
Trust administrative expenses 141 267 185 95
------ ------ ------ ------
Cash earnings 8,337 8,317 9,513 8,031
Cash distributions 8,337 8,317 9,513 8,031
Cash distributions per unit 0.390 0.389 0.445 0.375
(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
41
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, 1996 ($25.93 per barrel),
December 31, 1995 ($19.58 per barrel) and December 31, 1994 ($17.75 per
barrel). Because the reserve volumes attributable to the Trust are
estimated using an allocation of reserve volumes based on estimated
future production and on the current WTI Price, a change in the timing of
estimated production or a change in the WTI price will result in a change
in the Trust's estimated reserve volumes. Therefore, the estimated
reserve volumes attributable to the Trust will vary if different
production estimates and prices are used.
In addition to production estimates and prices, reserve volumes
attributable to the Trust are affected by the amount of Chargeable Costs
that will be deducted in determining the Per Barrel Royalty. The Royalty
Interest includes a provision under which, in years subsequent to 2001,
if additions to the Field's proved reserves from January 1, 1988 (after
certain adjustments) do not meet certain specified levels, Chargeable
Costs will be reduced up to a maximum amount of $1.20 per barrel in each
year. Under the provisions of FASB 69, no consideration can be given to
reserves not considered proved at the present time. Accordingly, in
estimating the reserve volumes attributable to the Trust, Chargeable
Costs were reduced by the maximum amount in years subsequent to 1996,
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, 1996, 1995 and 1994 based on the Company's latest
reserve estimate at such time, the WTI Prices on December 31, 1996, 1995
and 1994 and a reduction in Chargeable Costs in years subsequent to 1996,
were estimated to be 111, 81 and 81 million barrels, respectively (of
which 102, 80 and 81 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, 1996, 1995 and 1994 the standardized measure of
42
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 $25.93, $19.58 and $17.75,
respectively, were as follows (in thousands):
December 31, December 31, December 31,
1996 1995 1994
------------ ------------ ------------
Future net cash flows $ 779,517 331,052 257,080
10% annual discount for
estimated timing of
cash flows (367,217) (128,458) (93,935)
--------- --------- --------
Standardized measure of
discounted future net
cash flow relating to
proved reserves (a) $ 412,300 202,594 163,145
========= ========= ========
<FN>
(a) The standardized measure of discounted future net cash flow relating
to proved reserves, estimated without reducing Chargeable Costs in
years subsequent to 1996, would be $388,249, $202,602 and $154,200
at December 31, 1996, 1995 and 1994, respectively.
The following are the principal sources of the change in the standardized
measure of discounted future net cash flows (in thousands):
1996 1995 1994
---- ---- ----
Revisions of prior estimates:
Reserve volumes $ 21,565 1,678 28,853
WTI price 278,082 79,833 (115,530)
Chargeable costs - inflation (18,891) (11,791) (3,300)
Production taxes (40,513) (10,279) (17,093)
Other (1,807) (1,504) (827)
-------- -------- ---------
238,436 57,937 123,163
Royalty income received (b) (48,989) (34,803) (31,707)
Accretion of discount 20,259 16,315 6,517
-------- -------- ---------
Net increase during the year $ 209,706 39,449 97,973
======== ======== =========
43
<FN>
(b) Royalty income received for 1996, 1995 and 1994 includes the royalty
applicable to the period October 1, 1996 through December 31, 1996
($15,138), October 1, 1995 through December 31, 1995 ($8,411) and
October 1, 1994 through December 31, 1994 ($8,478), which was
received by the Trust in January 1997, 1996 and 1995, respectively.
The changes in quantities of proved oil and condensate were as follows
(thousands of barrels):
Estimated net proved reserves of oil
and condensate at December 31, 1994 80,991
Production (5,395)
Change in timing of estimated production 5,395
--------
Estimated net proved reserves of oil
and condensate at December 31, 1995 80,991
Production (5,410)
Change in timing of estimated production 35,485
--------
Estimated net proved reserves of oil
and condensate at December 31, 1996 111,066
========
Proved reserves:
December 31, 1994 80,991
========
December 31, 1995 80,991
========
December 31, 1996 111,066
========
As of December 31, 1996, the 111.1 million barrels of proved reserves
were comprised of 102.0 million barrels of proved developed reserves and
9.1 million barrels of proved undeveloped reserves.
44
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Trust has no directors or executive officers. The Trustee has only
such rights and powers as are necessary to achieve the purposes of the Trust.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable.
ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Unit Ownership of Certain Beneficial Owners.
The following table sets forth information regarding the ownership of
Units by all persons known to the Trustee as of March 26, 1997 to be the
beneficial owners of more than five percent of the Units. Except as noted
below, to the Trustee's knowledge, such owners have sole voting and investment
power for the Units indicated as beneficially owned by them.
Name Amount
And Address And Nature Of Percentage of
Of Beneficial Beneficial Outstanding
Owner Ownership Units
------------- ------------- -------------
J. Taylor Crandall 1,259,500 (a) 5.9%
Keystone, Inc.
201 Main Street, Suite 3100
Fort Worth, TX 76102
Robert W. Bruce III 1,259,500 (b) 5.9
Robert Bruce Management Co., Inc.
P.O. Box 252
South Salem, NY 10590
Alpine Capital, L.P. 1,189,300 5.6
201 Main Street, Suite 3100
Fort Worth, TX 76102
Algenpar, Inc. 1,189,300 (c) 5.6
201 Main Street, Suite 3100
Fort Worth, TX 76102
45
<FN>
- ---------------
(a) J. Taylor Crandall has shared voting power and investment power,
solely in his capacity as president and sole stockholder of Algenpar, Inc.,
which is one of two general partners of Alpine Capital, L.P., with respect to
1,189,300 Units, and shared voting power and investment power in his capacity
as a director of The Anne T. and Robert M. Bass Foundation (the "Bass
Foundation") with respect to 70,200 Units beneficially owned by the Bass
Foundation.
(b) Robert W. Bruce III has shared voting power and investment power,
solely in his capacity as one of two general partners of Alpine Capital, L.P.,
with respect to 1,189,300 Units, and shared voting power and investment power
in his capacity as a principal of The Robert Bruce Management Co., Inc., which
has shared investment discretion over 70,200 Units beneficially owned by the
Bass Foundation.
(c) Algenpar, Inc. has shared voting power and investment power with
respect to 1,189,300 Units beneficially owned by Alpine Capital, L.P., solely
in its capacity as one of the general partners thereof.
Unit Ownership of Management
Neither the Company, Standard Oil, nor BP owns any Units. No Units are
owned by The Bank of New York, as Trustee or in its individual capacity, or by
The Bank of New York (Delaware), as co-trustee or in its individual capacity.
Changes in Control
The Trustee knows of no arrangement, including the pledge of Units, the
operation of which may at a subsequent date result in a change in control of
the Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
46
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) FINANCIAL STATEMENTS
The following financial statements of the Trust are included in Part II,
Item 8:
Independent Auditors' Report
Statements of Assets, Liabilities and Trust Corpus
as of December 31, 1996 and 1995
Statements of Cash Earnings and Distributions for the years
ended December 31, 1996, 1995, and 1994
Statements of Changes in Trust Corpus for the years
ended December 31, 1996, 1995, and 1994
Notes to Financial Statements
(b) FINANCIAL STATEMENT SCHEDULES
All financial statement schedules have been omitted because they are
either not applicable, not required or the information is set forth in the
financial statements or notes thereto.
(c) EXHIBITS
4.1 BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among
The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of
New York, Trustee, and F. James Hutchinson, Co-Trustee.
4.2 Overriding Royalty Conveyance dated February 27, 1989 between BP
Exploration (Alaska) Inc. and The Standard Oil Company.
4.3 Trust Conveyance dated February 28, 1989 between The Standard Oil
Company and BP Prudhoe Bay Royalty Trust.
4.4 Support Agreement dated as of February 28, 1989 among The British
Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The standard
Oil Company and BP Prudhoe Bay Royalty Trust.
27 Financial Data Schedule
(d) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the quarter ended December 31, 1996.
47
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
BP PRUDHOE BAY ROYALTY TRUST
THE BANK OF NEW YORK, as Trustee
By: /s/ Marie Trimboli
----------------------------
Marie Trimboli
Assistant Treasurer
March 27, 1997
The Registrant is a trust and has no officers, directors, or persons
performing similar functions. No additional signatures are available and none
have been provided.
48
INDEX TO EXHIBITS
Exhibit Exhibit
No. Description
------- -----------
4.1 BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989
among The Standard Oil Company, BP Exploration (Alaska) Inc., The
Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee.
Filed herewith.
4.2 Overriding Royalty Conveyance dated February 27, 1989 between BP
Exploration (Alaska) Inc. and The Standard Oil Company. Filed
herewith.
4.3 Trust Conveyance dated February 28, 1989 between The Standard Oil
Company and BP Prudhoe Bay Royalty Trust. Filed herewith.
4.4 Support Agreement dated as of February 28, 1989 among The British
Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The
standard Oil Company and BP Prudhoe Bay Royalty Trust. Filed
herewith.
27 Financial Data Schedule. Filed herewith.