BP Prudhoe Bay Royalty Trust 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year ended December 31, 2005
OR
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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)
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DELAWARE |
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State or other jurisdiction
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13-6943724 |
of incorporation or organization)
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(I.R.S. Employer Identification No.) |
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THE BANK OF NEW YORK, TRUSTEE |
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101 BARCLAY STREET |
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NEW YORK, NEW YORK
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10286 |
(Address of principal executive offices)
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(Zip Code) |
Registrants telephone number, including area code: (212) 815-6908
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange on Which Registered |
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UNITS OF BENEFICIAL INTEREST
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NEW YORK STOCK EXCHANGE |
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act.
Yes o No þ
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 þ No o
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 registrants 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.
þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act Yes o No þ
The aggregate market value of Units held by nonaffiliates (computed by reference to the
closing sale price in New York Stock Exchange transactions on June 30, 2005 (the last business day
of the registrants most recently completed second fiscal quarter) was approximately
$1,531,598,000.
As of March 16, 2006, 21,400,000 Units of Beneficial Interest were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
TABLE OF CONTENTS
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i
PART I
ITEM 1. BUSINESS
INTRODUCTION
BP Prudhoe Bay Royalty Trust (the Trust) was created as a Delaware business trust by 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. (BP Alaska), The Bank of New
York, as trustee (the Trustee), and F. James Hutchinson, co-trustee (The Bank of New York
(Delaware), successor co-trustee). BP Alaska and Standard Oil are wholly owned subsidiaries of BP
p.l.c. (BP). The Trustees corporate trust offices are located at 101 Barclay Street, New York,
New York 10286 and its telephone number is (212) 815-6908.
The Trust electronically files annual reports on Form 10-K, quarterly reports on Form 10-Q
and, when certain events require them, current reports on Form 8-K with the Securities and Exchange
Commission (SEC). The public may read and copy any materials filed by the Trust with the SEC at
the SECs Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may
obtain information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and
information statements, and other information regarding issuers (including the Trust) that file
electronically with the SEC. The address of the SECs web site
is http://www.sec.gov.
The Trust does not have an Internet web site from which information concerning the Trust may
be obtained; however the Trustee will provide paper or electronic copies of the Trusts reports on
Form 10-K, Form 10-Q and Form 8-K, and amendments to those reports, free of charge upon request as
soon as reasonably practicable after the Trust files them with the SEC. Requests for copies of
reports may be made by mail to: The Bank of New York, 101 Barclay Street, New York, NY 10286,
Attention: Mr. Remo Reale, Corporate Trust Department; by telephone to: (212) 815-6908; or by
e-mail to: rreale@bankofny.com.
The information in this report relating to the Prudhoe Bay Unit, the calculation of royalty
payments and certain other matters has been furnished to the Trustee by BP Alaska.
Forward-Looking Statements
Various sections of this report contain forward-looking statements (that is, statements
anticipating future events or conditions and not statements of historical fact). Words such as
anticipate, expect, believe, intend, plan or project, and should, would, could,
potentially, possibly or may, and other words that convey uncertainty of future events or
outcomes are intended to identify forward-looking statements. Forward-looking statements in this
report are subject to a number of risks and uncertainties beyond the control of the Trustee. These
risks and uncertainties include such matters as future changes in oil prices, oil production
levels, economic activity, domestic and international political events and developments,
legislation and regulation, and certain changes in expenses of the Trust.
The actual results, performance and prospects of the Trust could differ materially from those
expressed or implied by forward-looking statements. Descriptions of some of the risks that could
affect the future performance of the Trust appear in the following Item 1A, Risk Factors, and
elsewhere in
this report. There may be additional risks of which the Trustee is unaware or which are currently
deemed immaterial.
In the light of these risks, uncertainties and assumptions, you should not rely unduly on any
forward-looking statements. Forward-looking events and outcomes discussed in this report may not
occur or may transpire differently. The Trustee undertakes no obligation to update forward-looking
statements after the date of this report, except as required by law, and all such forward-looking
statements in this report are qualified in their entirety by the preceding cautionary statements.
THE TRUST
Trust Property
The property of the Trust consists of an overriding royalty interest (the Royalty Interest)
and cash and cash equivalents held by the Trustee from time to time. The Royalty Interest 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 BP
Alaska as of February 28, 1989 in the Prudhoe Bay oil field located on the North Slope in Alaska.
The Prudhoe Bay field is one of four contiguous North Slope oil fields that are operated by BP
Alaska and are known collectively as the Prudhoe Bay Unit. The Royalty Interest was conveyed to the
Trust by an Overriding Royalty Conveyance dated February 27, 1989 from BP Alaska to Standard Oil
and a Trust Conveyance dated February 28, 1989 from Standard Oil to the Trust. Copies of the
Overriding Royalty Conveyance and the Trust Conveyance are filed with the SEC as exhibits to this
report. The Overriding Royalty Conveyance and the Trust Conveyance are referred to collectively as
the Conveyance.
The Royalty Interest is a non-operational interest in minerals. The Trust does not have the
right to take oil and gas in kind, nor does it have any right to take over operations or to share
in any operating decision with respect to BP Alaskas working interest in the Prudhoe Bay field. BP
Alaska is not obligated to continue to operate any well or maintain or attempt to maintain in force
any portion of its working interest when, in its reasonable and prudent business judgment, the well
or interest ceases to produce or is not capable of producing oil or gas in paying quantities.
Employees
The Trust has no employees. All administrative functions of the Trust are performed by the
Trustee.
Duties and Powers of the Trustee
The duties of the Trustee are specified in the Trust Agreement and the laws of the State of
Delaware. 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. A copy of the Trust Agreement is
filed as an exhibit to this report and is available upon request from the Trustee.
The basic function of the Trustee is to collect income from the Royalty Interest, to pay all
expenses, charges and obligations of the Trust from the Trusts income and assets, and to pay
available
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* |
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The term barrel is a unit of
measure of petroleum liquids equal to 42 United States gallons corrected to 60
degrees Fahrenheit temperature. |
2
cash to Unit holders. Because of the passive nature of the Trusts assets and the
restrictions on the power of the Trustee to incur obligations, the only liabilities incurred by the
Trust are the Trustees fees and routine administrative expenses, including accounting, legal and
other professional fees.
The Trust Agreement grants the Trustee only the rights and powers necessary to achieve the
purposes of the Trust. The Trust Agreement prohibits the Trust from engaging in any business or
commercial activity or, with certain exceptions, any investment activity and from using any assets
of the Trust to acquire any oil and gas lease, royalty or other mineral interest.
Except in certain circumstances, the Trustee is entitled to be indemnified out of the assets
of the Trust for any liability or loss incurred by it in the performance of its duties unless the
loss results from its negligence, bad faith or fraud or from expenses incurred in carrying out its
duties that exceed the compensation and reimbursement to which it is entitled under the Trust
Agreement.
Sales of Assets, Borrowings and Reserves
With certain exceptions, the Trustee may sell Trust assets only if authorized to do so by vote
of the holders of 70 percent of the Units outstanding. However, if the sale is made in order to pay
specific liabilities of the Trust then due and involves a part, but not all or substantially all,
of the Trust properties, the sale only needs to be approved by the vote of holders of a majority of
the Units. Any sale of Trust properties must be for cash unless otherwise authorized by the Unit
holders. The Trustee is obligated to distribute the available net proceeds of any such sale to the
Unit holders after establishing reserves for liabilities of the Trust.
The Trustee has the power to borrow on behalf of the Trust or to sell Trust assets to pay
liabilities of the Trust and to establish a reserve for the payment of liabilities without the
consent of the Unit holders under the following circumstances:
The Trustee may borrow from a lender not affiliated with the Trustee, if cash on hand
is not sufficient to pay current liabilities, it is not practical to pay such liabilities
out of funds anticipated to be available in a subsequent quarter, and failure to pay the
liabilities would subject the Trust property to the risk of loss or diminution in value. To
secure payment of its borrowings on behalf of the Trust, the Trustee is authorized to
encumber the Trusts assets, and to carve out and convey production payments. The borrowing
must be on terms which (in the opinion of an investment banking firm or commercial banking
firm) are commercially reasonable when compared to other available alternatives. No
distributions to Unit holders may be made until the borrowings by the Trust have been repaid
in full.
If the Trustee is unable to borrow to pay Trust liabilities, the Trustee may sell Trust
assets if it determines that the failure to pay the liabilities at a later date will be
contrary to the best interest of the Unit holders and that it is not practicable to submit
the sale to a vote of the Unit holders. The sale must be made for cash at a price which (in
the opinion of an investment banking firm or commercial banking firm) is at least equal to
the fair market value of the interest sold and is made on commercially reasonable terms when
compared to other available alternatives.
The Trustee has the right to establish a cash reserve for the payment of material
liabilities of the Trust which may become due if it determines that it is not practical to
pay such liabilities out of funds anticipated to be available and that, in the absence of a
reserve, the Trust
3
property is subject to the risk of loss or diminution in value, or the
Trustee is subject to the risk of personal liability for such liabilities.
In order for the Trustee to borrow, sell assets to pay Trust liabilities or establish a
reserve for Trust liabilities, the Trustee must receive an unqualified written legal opinion that
the action 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. If the Trustee is unable to obtain the required
legal opinion, it still may proceed with the borrowing or sale, or establish the reserve, if it
determines that the failure to do so will be materially detrimental to the Unit holders considered
as a whole or will subject the Trustee to the risk of personal liability for liabilities of the
Trust.
In 1999, the Trustee established a $1,000,000 cash reserve to provide liquidity to the Trust
during any future periods in which the Trust does not receive a distribution from BP Alaska. See
Item 7 in Part II below.
Amendment of the Trust Agreement
The Trust Agreement may be amended without a vote of the Unit holders to cure an ambiguity, to
correct or supplement any provision of the Trust Agreement that may be inconsistent with any other
provision or to make any other provision with respect to matters arising under the Trust Agreement
that do not adversely affect the Unit holders. The Trust Agreement may also be amended with the
approval of holders of a majority of the outstanding Units. However, no such amendment may alter
the relative rights of Unit holders, unless approved by the affirmative vote of holders of 100
percent of the outstanding Units and by the Trustee, or reduce or delay the distributions to the
Unit holders or make certain other changes unless approved by the affirmative vote of holders of at
least 80 percent of the outstanding 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, doing business
and authorized to exercise trust powers under the laws of the United States, any state thereof or
the District of Columbia, 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 Delaware, any successor
trustee must be a resident of Delaware or have a principal office in Delaware. No resignation or
removal of the Trustee will become effective until a successor trustee has accepted appointment.
Termination of the Trust
The Trust is irrevocable. BP Alaska has no power to terminate the Trust. The Trust will
terminate: (a) on or before December 31, 2010 if holders of at least 70 percent of the outstanding
Units vote to terminate the Trust, or (b) after December 31, 2010 either (i) holders at least 60
percent of the outstanding Units vote to terminate the Trust or (ii) the net revenues from the
Royalty Interest for two
4
successive years commencing after 2010 are less than $1,000,000 per year
(unless the net revenues during the two-year period have been materially and adversely affected by
certain extraordinary events).
Upon termination of the Trust, BP Alaska will have an option to purchase the Royalty Interest
at a price equal to the greater of (i) the fair market value of the Trust property as set forth in
an opinion of an investment banking firm, commercial banking firm or other entity qualified to give
an opinion as to the fair market value of the assets of the Trust, or (ii) the number of
outstanding Units multiplied by (a) the closing price of Units on the day of termination of the
Trust on the stock exchange on which the Units are listed, or (b) if the Units are not listed on
any stock exchange but are traded in the over-the-counter market, the closing bid price on the day
of termination of the Trust as quoted on the NASDAQ National Market System. The purchase must be
for cash unless holders of 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.
If BP Alaska does not exercise its option, the Trustee will sell the Trust properties on 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 the matter to a vote of the Unit holders, and the sale is made at a price at
least equal to the fair market value of the Trust property as set forth in the opinion mentioned
above and on terms and conditions deemed commercially reasonable by the investment banking firm,
commercial banking firm or other entity rendering the opinion.
The Trustee will distribute all available proceeds to the Unit holders after satisfying all
existing liabilities of the Trust and establishing adequate reserves for the payment of contingent
liabilities.
In the Trust Agreement, Unit holders 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 Unit Holders
Unit holders possess certain voting rights, but their voting rights are not comparable to
those of shareholders of a corporation. For example, there is no requirement for annual meetings of
Unit holders or for periodic reelection of the Trustee.
A meeting of the Unit holders may be called at any time to act with respect to any matter as
to which the Trust Agreement authorizes the Unit holders to act. Any such meeting may be called by
the Trustee in its discretion and will be called (i) as soon as practicable after receipt of a
written request by BP Alaska or a written request that sets forth in reasonable detail the action
proposed to be taken at the
meeting and is signed by holders of at least 25 percent of the outstanding Units or (ii) when
required by applicable laws or regulations or the New York Stock Exchange. All meetings of Unit
holders are required to be held in Manhattan, New York City.
5
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 assigned to it. The royalty
payable to the Trust for each calendar quarter is the sum of the amounts obtained by multiplying
Royalty Production for each day in the calendar quarter by the Per Barrel Royalty for that day. 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 BP Alaskas working interest
in the Prudhoe Bay Unit for the quarter, net of the State of Alaska royalty and less the value of
any applicable payments made to affiliates of BP Alaska.
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 the quarter
from the Prudhoe Bay (Permo-Triassic) Reservoir and allocated to the oil and gas leases owned by BP
Alaska in the Prudhoe Bay Unit as of February 28, 1989 (the BP Working Interests). 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 BP Working Interests for any calendar quarter is the total production
of oil and condensate for the quarter, net of the State of Alaska royalty, divided by the number of
days in the quarter.
Per Barrel Royalty
The Per Barrel Royalty for any day is the WTI Price for the day less the sum of (i)
Chargeable Costs multiplied by the Cost Adjustment Factor and (ii) Production Taxes.
WTI Price
The WTI Price for any trading day is (i) the price (in dollars per barrel) for West Texas
intermediate crude oil of standard quality having a specific gravity of 40 API degrees for delivery
at Cushing, Oklahoma (West Texas Crude) quoted for that trading day by whichever of The Wall
Street Journal, Reuters, or Platts Oilgram Price Report, in that order, publishes West Texas Crude
price quotations for the trading day, or (ii) if the price of West Texas Crude is not published by
one of those publications, the WTI Price will be the simple average of the daily mean prices (in
dollars per barrel) quoted for West Texas Crude by one major oil company, one petroleum broker and
one petroleum trading company designated by BP Alaska, in each case unaffiliated with BP and having
substantial U.S. operations, until published price quotations are again available. If prices for
West Texas Crude are not quoted so as to permit the calculation of the WTI Price, the price of
West Texas Crude, for the purposes of calculating the WTI Price will be the price of another
light sweet domestic crude oil of standard quality designated by BP Alaska and approved by the
Trustee, with appropriate allowance for transportation costs to the Gulf coast (or another
appropriate location) to equilibrate its price to the WTI Price. The WTI Price for any day which is
not a trading day is the WTI Price for the preceding trading day.
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 BP Alaskas actual costs of
6
production. Chargeable Costs per barrel were $10.75 during 2001, $11.25 during 2002, $11.75 during
2003, $12.00 during 2004, and $12.25 during 2005. Chargeable Costs for 2006 and subsequent years
are shown in the following table:
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Calendar |
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Chargeable Costs |
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Calendar |
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Chargeable Costs |
year |
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per barrel |
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year |
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per barrel |
2006 |
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$ |
12.50 |
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2014 |
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$ |
16.90 |
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2007 |
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12.75 |
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2015 |
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17.00 |
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2008 |
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13.00 |
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2016 |
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17.10 |
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2009 |
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13.25 |
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2017 |
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17.20 |
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2010 |
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14.50 |
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2018 |
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20.00 |
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2011 |
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16.60 |
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2019 |
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23.75 |
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2012 |
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16.70 |
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2020 |
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26.50 |
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2013 |
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16.80 |
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After 2020, Chargeable Costs increase at a uniform rate of $2.75 per year.
Cost Adjustment Factor
The Cost Adjustment Factor for a quarter is the ratio of the Consumer Price Index published
for the most recently past February, May, August or November to 121.1 (the Consumer Price Index for
January 1989). 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. If the average WTI Price for any calendar quarter falls to $18.00 or less, the Cost
Adjustment Factor for that quarter will be the Cost Adjustment Factor for the immediately preceding
quarter. If the average WTI Price returns to more than $18.00 for a later quarter, adjustments to
the Cost Adjustment Factor resume, but with an adjustment to the formula that excludes changes in
the Consumer Price Index during the period that adjustments to the Cost Adjustment Factor were
suspended.
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, computed at defined statutory
rates. In the case of taxes based upon wellhead or field value, the Conveyance provides that the
WTI Price less the product of $4.50 and the Cost Adjustment factor will be deemed to be the
wellhead or field value. At the present time, the Production Taxes payable with respect to the
Royalty Production are the Alaska Oil and Gas Properties Production Tax (Alaska Production Tax).
For the purposes of the Royalty Interest, the Alaska Production Tax is computed without regard to
the economic limit factor, if any, as the greater of the percentage of value amount (based on
the statutory rate and the wellhead value as defined above) and the cents per barrel amount. As
of the date of this report, the statutory rate for the purpose of calculating the percentage of
value amount is 15 percent. In February 2006, the Governor of Alaska proposed legislation that
would replace the Alaska Production Tax with a net profits tax on
producers (see Item 1A below). A surcharge to the Alaska Production Tax increased Production
Taxes by $0.05 per barrel of net production in 1989. Due to the spill response fund having reached
$50 million in 1995, $0.02 per barrel of the surcharge has been indefinitely suspended. If 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 $0.03 per barrel
surcharge is not affected by the funds balance and will continue to be imposed at all times.
7
Per Barrel Royalty Calculations
The following table shows how the above-described factors interacted during the past five
years to produce the Per Barrel Royalty paid for the calendar quarters indicated.
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Cost |
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Adjusted |
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Average |
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Chargeable |
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Adjustment |
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Chargeable |
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Production |
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Per Barrel |
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WTI Price |
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Costs |
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Factor |
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Costs |
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Taxes |
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Royalty |
2001: |
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1st Qtr |
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$ |
28.83 |
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$ |
10.75 |
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1.354 |
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$ |
14.55 |
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$ |
3.44 |
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$ |
10.84 |
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2nd Qtr |
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27.92 |
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10.75 |
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1.368 |
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14.71 |
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3.29 |
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9.92 |
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3rd Qtr |
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26.82 |
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|
|
10.75 |
|
|
|
1.367 |
|
|
|
14.69 |
|
|
|
3.13 |
|
|
|
9.00 |
|
4th Qtr |
|
|
20.41 |
|
|
|
10.75 |
|
|
|
1.366 |
|
|
|
14.68 |
|
|
|
2.17 |
|
|
|
3.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Qtr |
|
|
21.67 |
|
|
|
11.25 |
|
|
|
1.369 |
|
|
|
15.40 |
|
|
|
2.36 |
|
|
|
3.91 |
|
2nd Qtr |
|
|
26.28 |
|
|
|
11.25 |
|
|
|
1.384 |
|
|
|
15.57 |
|
|
|
3.04 |
|
|
|
7.67 |
|
3rd Qtr |
|
|
28.33 |
|
|
|
11.25 |
|
|
|
1.391 |
|
|
|
15.65 |
|
|
|
3.34 |
|
|
|
9.34 |
|
4th Qtr |
|
|
28.25 |
|
|
|
11.25 |
|
|
|
1.396 |
|
|
|
15.70 |
|
|
|
3.33 |
|
|
|
9.22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Qtr |
|
|
34.08 |
|
|
|
11.75 |
|
|
|
1.410 |
|
|
|
16.57 |
|
|
|
4.19 |
|
|
|
13.32 |
|
2nd Qtr |
|
|
29.07 |
|
|
|
11.75 |
|
|
|
1.413 |
|
|
|
16.60 |
|
|
|
3.44 |
|
|
|
9.03 |
|
3rd Qtr |
|
|
30.30 |
|
|
|
11.75 |
|
|
|
1.421 |
|
|
|
16.70 |
|
|
|
3.62 |
|
|
|
9.98 |
|
4th Qtr |
|
|
31.23 |
|
|
|
11.75 |
|
|
|
1.421 |
|
|
|
16.69 |
|
|
|
3.76 |
|
|
|
10.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Qtr |
|
|
35.18 |
|
|
|
12.00 |
|
|
|
1.434 |
|
|
|
17.20 |
|
|
|
4.34 |
|
|
|
13.64 |
|
2nd Qtr |
|
|
38.31 |
|
|
|
12.00 |
|
|
|
1.456 |
|
|
|
17.47 |
|
|
|
4.79 |
|
|
|
16.05 |
|
3rd Qtr |
|
|
43.78 |
|
|
|
12.00 |
|
|
|
1.459 |
|
|
|
17.51 |
|
|
|
5.61 |
|
|
|
20.66 |
|
4th Qtr |
|
|
48.35 |
|
|
|
12.00 |
|
|
|
1.471 |
|
|
|
17.65 |
|
|
|
6.29 |
|
|
|
24.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Qtr |
|
|
49.70 |
|
|
|
12.25 |
|
|
|
1.477 |
|
|
|
18.09 |
|
|
|
6.49 |
|
|
|
25.12 |
|
2nd Qtr |
|
|
53.09 |
|
|
|
12.25 |
|
|
|
1.497 |
|
|
|
18.34 |
|
|
|
6.98 |
|
|
|
27.77 |
|
3rd Qtr |
|
|
63.03 |
|
|
|
12.25 |
|
|
|
1.512 |
|
|
|
18.53 |
|
|
|
8.46 |
|
|
|
36.04 |
|
4th Qtr |
|
|
60.01 |
|
|
|
12.25 |
|
|
|
1.521 |
|
|
|
18.63 |
|
|
|
8.01 |
|
|
|
33.37 |
|
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 BP Alaska, 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 securities.
8
Distributions of Income
BP Alaska makes quarterly payments to the Trust of the amounts due with respect to the Trusts
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 pays all expenses of the Trust for each quarter on the Quarterly Record Date to the
extent possible, then distributes the excess, if any, of the cash received by the Trust over the
Trusts expenses, net of any additions to or subtractions from the cash reserve established for the
payments of estimated liabilities (the Quarterly Distribution), to the persons in whose names the
Units were registered at the close of business on the Quarterly Record Date.
The Trust Agreement requires the Trustee to pay the Quarterly Distribution to Unit holders on
the fifth day after the Trustees receipt of the amount paid by BP Alaska. Cash balances held by
the Trustee for distribution are required to be invested in United States government or agency
obligations secured by the full faith and credit of the United States (Government Obligations)
or, if Government Obligations that mature 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 Government Obligations or repurchase
agreements, the Trustee may invest funds overnight in a time deposit with a bank meeting the
foregoing capital requirement (including The Bank of New York).
Reports to Unit Holders
After the end of each calendar year, the Trustee mails a report to the persons
who held Units of record during the year containing information to enable them to make the
calculations necessary for federal and Alaska income tax purposes, including the calculation of any
depletion or other deduction which may be available to them for the calendar year. In addition,
after the end of each calendar year the Trustee mails Unit holders an annual report containing a
copy of this Form 10-K and certain other information required by the Trust Agreement.
Limited Liability of Unit Holders
The Trust Agreement provides that the Unit holders 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, it 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 Unit holders, the Trustee may require each holder whose nationality or other status is
an issue in the proceeding to dispose of his Units to a party not of the nationality or other
status at issue in the proceeding. If any holder fails to dispose of his Units within 30 days after
receipt of notice from the Trustee to do so, the Trustee will
9
redeem any Unit not so transferred
within 90 days after the end of the 30-day period specified in the notice for a cash price per Unit
equal to the fair market value of the Units. Units redeemed by the Trustee will be cancelled.
The Trustee may 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 the Employee Retirement Income Security Act of 1970, or under the Internal
Revenue Code of 1986, the Units subject to the Trustees right of redemption will be purchased by
BP Alaska or a designee of BP Alaska.
Issuance of Additional Units
The Trust Agreement provides that BP Alaska 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, the Trust may issue up to an additional 18,600,000 Units. BP Alaska has not
conveyed any additional royalty interests to the Trust, and the Trust has not issued any additional
Units.
THE BP SUPPORT AGREEMENT
BP has agreed to provide financial support to BP Alaska in meeting its payment obligations to
the Trust in a Support Agreement dated February 28, 1989 among BP, BP Alaska, Standard Oil and the
Trust (the Support Agreement). Within 30 days after it receives notice, BP will ensure that BP
Alaska can perform its payment obligations under the Trust Agreement and the Conveyance, including
contributing to BP Alaska the funds necessary to make such payments. BPs obligations under the
Support Agreement are unconditional and directly enforceable by Unit holders.
Neither BP nor BP Alaska may transfer or assign its rights or obligations under the Support
Agreement without the prior written consent of the Trustee, except that BP can arrange for its
obligations to be performed by any its affiliates so long as BP remains responsible for ensuring
that its obligations are performed in a timely manner.
BP Alaska 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 BP Alaskas
payment obligations under 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 BP Alaskas working interest in the Prudhoe Bay Unit if the
transferee agrees in writing to assume and be bound by BPs obligation under the Support Agreement.
The transferees agreement to assume BPs obligations must be reasonably satisfactory to the
Trustee and the transferee must be an entity having a rating of its unsecured, unsupported long
term debt of at least A3 from
Moodys Investors Service, Inc., a rating of at least A- from Standard & Poors or an
equivalent rating from at least one nationally-recognized statistical rating organization (after
giving effect to the sale or transfer and the assumption of all of BP Alaskas obligations under
the Conveyance and all of BPs obligations under the Support Agreement).
10
THE PRUDHOE BAY UNIT AND FIELD
Prudhoe Bay Unit Operation and Ownership
Since several oil companies besides BP Alaska hold acreage within the Prudhoe Bay field, as
well as the contiguous Endicott, Lisburne and Pt. McIntyre fields, the Prudhoe Bay Unit was
established to optimize field development. Other owners of these fields include affiliates of Exxon
Mobil Corporation, ConocoPhillips, ChevronTexaco Corporation and Forest Oil Corporation. The
Trusts Royalty Interest pertains only to production from the Prudhoe Bay field and does not
include production from the Endicott, Lisburne and Pt. McIntyre fields.
The operations of BP Alaska and the other working interest owners in the Prudhoe Bay Unit are
governed by an agreement dated April 1, 1977 among the State of Alaska and the 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 Prudhoe Bay Unit Operating Agreement specifies the allocation of production and costs to
the working interest owners. It also defines operator responsibilities and voting requirements and
is unusual in its establishment of separate participating areas for the gas cap and oil rim. Since
July 1, 2000, BP Alaska has been the sole operator of the Prudhoe Bay Unit.
The ownership of the Prudhoe Bay Unit by participating area as of December 31, 2005 is shown
in the following table:
|
|
|
|
|
|
|
|
|
|
|
Oil rim |
|
Gas cap |
BP Alaska |
|
|
26.35 |
%(a) |
|
|
26.35 |
%(b) |
Exxon Mobil |
|
|
36.40 |
|
|
|
36.40 |
|
ConocoPhillips |
|
|
36.07 |
|
|
|
36.07 |
|
Others |
|
|
1.18 |
|
|
|
1.18 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100.00 |
% |
|
|
100.00 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The Trusts share of oil production is computed based on BP Alaskas ownership interest
in the oil rim participating area of 50.68 percent as of February 28, 1989. Subsequent
decreases in BP Alaskas participation in oil rim ownership do not affect calculation of
Royalty Production from the BP Working Interests and have not decreased the Trusts Royalty
Interest. |
|
(b) |
|
The Trusts share of condensate production is computed based on BP Alaskas ownership
interest in the gas cap participating area of 13.84 percent as of February 28, 1989.
Subsequent increases in BP Alaskas gas cap ownership do not affect calculation of Royalty
Production from the BP Working Interests and have not increased the Trusts Royalty
Interest. |
If BP Alaska fails to pay any costs and expenses chargeable to BP Alaska 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 BP Alaska agreed to pay 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 loss or liability incurred by BP Alaska or others attributable to BP
Alaskas working interest in the
11
Prudhoe Bay Unit or to the oil produced from it, and BP Alaska has
agreed to indemnify the Trust and hold it harmless against any such impositions.
BP Alaska 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. BP Alaska
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.
The Prudhoe Bay Field
The Prudhoe Bay field is located on the North Slope of Alaska, 250 miles north of the Arctic
Circle and 650 miles north of Anchorage. The Prudhoe Bay field extends approximately 12 miles by 27
miles and contains nearly 150,000 productive acres. The Prudhoe Bay field, which was discovered in
1968 by BP and others, has been in production since 1977 and is the largest producing oil field in
North America. As of December 31, 2005, approximately 10.8 billion barrels of oil and condensate
had been produced from the Prudhoe Bay field. Development is well advanced, with approximately $19
billion gross capital spent and a total of about 3,189 wells drilled.
Field 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 (PESS) formations. Underlying the Sadlerochit Group are the oil-bearing Lisburne and
Endicott formations. The net production allocated to the Royalty Interest pertains only to the
Ivishak and PESS formations, collectively known as the Prudhoe Bay (Permo-Triassic) Reservoir, and
does not pertain to the Lisburne and Endicott formations.
The Ivishak sandstone was deposited, commencing some 250 million years ago, during the Permian
and Triassic geologic periods. The sediments in the Ivishak are composed of sandstone, conglomerate
and shale which were deposited by a massive braided river and delta system that flowed from an
ancient mountain system to the north. Oil was trapped in the Ivishak by a combination of structural
and stratigraphic trapping mechanisms.
Gross reservoir thickness is 550 feet, with a maximum oil column thickness of 425 feet. The
original oil column is bounded on the top by a gas-oil contact, originally at 8,575 feet below sea
level across the main field, and on the bottom by an oil-water contact at approximately 9,000 feet
below sea level. A layer of heavy oil and tar overlays the oil-water contact in the main field and
has an average thickness of around 40 feet.
Oil Characteristics
The oil produced from the Prudhoe Bay (Permo-Triassic) Reservoir is a medium grade, low sulfur
crude with an average specific gravity of 27 API degrees. The gas cap composition is such that,
upon surfacing, a liquid hydrocarbon phase, known as condensate, is formed.
12
The Royalty Interest is 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.
Historical Production
Production from the Prudhoe Bay field began on June 19, 1977, with the completion of the
Trans-Alaska Pipeline System. As of December 31, 2005 there were about 1,111 active producing oil
wells, 33 gas reinjection wells, 82 water injection wells and 136 water and miscible gas injection
wells in the Prudhoe Bay field. Production from the Prudhoe Bay field has declined over the past
five years. The average well production rate was about 546 barrels of oil per day in 2001, 375
barrels per day in 2002, 350 barrels per day in 2003, 317 barrels per day in 2004 and 293 barrels
per day in 2005.
BP Alaskas share of the hydrocarbon liquids production from the Prudhoe Bay field includes
oil, condensate and natural gas liquids. Using the production allocation procedures from the
Prudhoe Bay Unit Operating Agreement, the Prudhoe Bay fields total production and the net share of
oil and condensate (net of State of Alaska royalty) allocated to the BP Working Interests have been
as follows during the past five years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Condensate |
|
|
|
|
|
|
Net to BP |
|
|
|
|
|
Net to BP |
Calendar |
|
|
|
|
|
Working |
|
|
|
|
|
Working |
year |
|
Total field |
|
Interests |
|
Total field |
|
Interests |
|
|
|
|
|
|
(thousand barrels per day) |
|
|
|
|
2001 |
|
|
324.9 |
|
|
|
144.1 |
|
|
|
131.2 |
|
|
|
15.9 |
|
2002 |
|
|
293.8 |
|
|
|
130.3 |
|
|
|
121.5 |
|
|
|
14.7 |
|
2003 |
|
|
273.2 |
|
|
|
121.2 |
|
|
|
113.8 |
|
|
|
13.8 |
|
2004 |
|
|
243.4 |
|
|
|
107.9 |
|
|
|
109.0 |
|
|
|
13.2 |
|
2005 |
|
|
228.9 |
|
|
|
101.5 |
|
|
|
96.4 |
|
|
|
11.7 |
|
Transportation of Prudhoe Bay Oil
Production from the Prudhoe Bay field is carried to Pump Station 1, the starting point for the
Trans-Alaska Pipeline System, through two 34-inch diameter transit lines, one from each half of the
Prudhoe Bay field. At Pump Station 1, Alyeska Pipeline Service Company, the pipeline operator,
meters the oil and pumps it in the 48-inch diameter pipeline to Valdez, almost 800 miles (1,287 km)
to the south, where it is either loaded onto marine tankers or stored temporarily. It takes the oil
about seven days to make the trip. The pipeline has a capacity of approximately 1.4 million barrels
of oil per day.
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 reserves.
Several different oil recovery mechanisms are currently active in the Prudhoe Bay field,
including pressure depletion, gravity drainage/gas cap expansion, water flooding and miscible gas
flooding. Separate yet integrated reservoir management strategies have been developed for the areas
affected by each of these recovery processes.
13
Reserve Estimates
The net proved remaining reserves of oil and condensate associated with the BP Working
Interests is approximately 1,043 million barrels as of December 31, 2005. This estimate of reserves
is based upon various assumptions, including a reasonable estimate of the allocation of hydrocarbon
liquids between oil and condensate according 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 become available. Such revisions often may be substantial. BP Alaska
anticipates that net production from current proved reserves allocated to the BP Working Interests
will exceed 90,000 barrels per day until the year 2012. The occurrence of major gas sales could
accelerate the time at which BP Alaskas net production would fall below 90,000 barrels per day,
due to the consequent decline in reservoir pressure. BP Alaska projects continued economic
production after 2012 at a declining rate until the year 2065; however, for the economic conditions
and production forecast as of December 31, 2005, it is estimated that royalty payments will cease
following the year 2023.
BP Alaskas 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 Prudhoe Bay 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 BP Working Interests will vary over time according to the
proportions of hydrocarbon liquid being allocated as condensate or as oil. 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 million barrels has been allocated to the working interest owners.
The reserves attributable to the Trusts Royalty Interest constitute only a part of the
overall reserves allocated to the BP Working Interests. BP Alaska has estimated that the net
remaining proved reserves attributable to the Trust as of December 31, 2005 were 85.3 million
barrels of oil and condensate. Using procedures specified in Financial Accounting Standards Board
Statement of Financial Standards No. 69, BP Alaska calculated that as of December 31, 2005
production of oil and condensate from the proved reserves allocated to the Trusts Royalty Interest
will result in estimated future net revenues to the Trust of $2,095.2 million, with a present value
of $1,209.7 million. BP Alaskas estimates of proved reserves and the estimated future net revenues
from the Prudhoe Bay Unit have been reviewed by Miller and Lents, Ltd., independent oil and gas
consultants, as set forth in their report following this section.
There is no precise method of forecasting the allocation of reserve volumes between BP Alaska
and the Trust. The Royalty Interest is not a working interest and the Trust is not entitled to
receive any specific volume of reserves from the Prudhoe Bay field. Rather, reserve volumes
attributable to the Trust at any given date are estimated by allocating to the Trust its share of
estimated future production from the Prudhoe Bay field based on WTI Prices and other economic
parameters in effect on the date of the evaluation.
14
The following table shows the net remaining proved reserves of oil and condensate allocated to
the BP Working Interests, the net proved reserves allocated to the Trust, and the WTI Prices on the
dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved Reserves |
|
|
|
|
BP Working |
|
|
|
|
|
WTI Price |
December 31 |
|
Interests (a) |
|
Trust (b) |
|
per barrel |
|
|
(million barrels) |
|
|
|
|
2001 |
|
|
961.7 |
|
|
|
43.2 |
|
|
$ |
19.78 |
|
2002 |
|
|
908.7 |
|
|
|
85.8 |
|
|
|
31.23 |
|
2003 |
|
|
858.7 |
|
|
|
77.9 |
|
|
|
32.55 |
|
2004 |
|
|
941.4 |
|
|
|
77.4 |
|
|
|
43.46 |
|
2005 |
|
|
1,043.0 |
|
|
|
85.3 |
|
|
|
61.04 |
|
|
|
|
(a) |
|
Includes proved undeveloped reserves of 112.5 million barrels at December 31, 2001; 5.5
million barrels at December 31, 2002; 139.9 million barrels at December 31, 2003; 115.4
million barrels at December 31, 2004; and 73.0 million barrels at December 31, 2005. |
|
(b) |
|
Includes proved undeveloped reserves of 0.03 million barrels at December 31, 2002; 11.0
million barrels at December 31, 2003; 9.1 million barrels at December 31, 2004; and 12.3
million barrels at December 31, 2005. No proved undeveloped reserves were attributable to
the Trust at December 31, 2001. |
The reserve volumes attributable to the Trust are estimated using an allocation of reserve
volumes based on estimated future production and the current WTI Price, and assume no future
movement in the Consumer Price Index and no future additions of proved reserves by BP Alaska. 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 7 (unaudited) of the Notes to Financial Statements in Item 8.
BP Alaska is under no obligation to make investments in development projects which would add
additional non-proved resources to proved reserves and cannot make such investments without the
concurrence of the Prudhoe Bay Unit working interest owners. However, several such investments
which would augment Prudhoe Bay projects are already in progress. These include additional
drilling, water flood expansions and miscible injection continuation/expansion projects. Other
possible investments could include expanded gas cycling, miscible/water flood infill drilling,
miscible injection supply increases to peripheral areas, heavy oil tar recovery and development of
the smaller reservoirs. While there is no assurance that
the Prudhoe Bay Unit working interest owners will make any such investments they do regularly
assess the technical and economic attractiveness of implementing further projects to increase
Prudhoe Bay Unit proved reserves.
In the event of changes in BP Alaskas 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.
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INDEPENDENT OIL AND GAS CONSULTANTS REPORT
February 6, 2006
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street, 8 West
New York, New York 10286
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Re:
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Estimates of Proved Reserves, |
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Future Production Rates, and |
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Future Net Revenues for the |
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BP Prudhoe Bay Royalty Trust |
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As of December 31, 2005 |
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, 2005. 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 3, 2006 addressed to
Mr. Remo J. Reale of The Bank of New York and signed by Ms. Maureen Johnson. Reviews were also
performed by Miller and Lents, Ltd. during this year or in previous years of (1) the procedures for
estimating and documenting Proved Reserves, (2) the estimates of in-place reservoir volumes, (3)
the estimates of recovery factors and production profiles for the various areas, pay zones,
projects, and recovery processes that are included in the estimate of Proved Reserves, (4) the
production strategy and procedures for implementing that strategy, (5) the sufficiency of the data
available for making estimates of Proved Reserves and production profiles, and (6) pertinent
provisions of the Prudhoe Bay Unit Operating Agreement, the Issues Resolution Agreement, the
Overriding Royalty Conveyance, the Trust Conveyance, the BP Prudhoe Bay Royalty
Trust Agreement, and other related documents referenced in the Form F-3 Registration Statement
filed with the Securities and Exchange Commission on August 7, 1989, by BP Exploration (Alaska)
Inc.
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Miller and Lents, Ltd.
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The Bank of New York
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February 6, 2006 |
Trustee, BP Prudhoe Bay Royalty Trust |
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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:
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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. |
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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. |
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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. |
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The estimated net remaining Proved Reserves attributable to the BP Prudhoe Bay
Royalty Trust as of December 31, 2005, of 85.31 million barrels of oil and condensate
are, in the aggregate, reasonable. Of the 85.31 million barrels of total Proved
Reserves, 73.03
million barrels are Proved Developed Reserves, and 12.28 million barrels are Proved
Undeveloped Reserves. |
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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, 2005 production of the Proved Reserves will result
in |
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Miller and Lents, Ltd.
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The Bank of New York
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February 6, 2006 |
Trustee, BP Prudhoe Bay Royalty Trust |
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Estimated Future Net Revenues of $2,095.2 million and Present Value of Estimated
Future Net Revenues of $1,209.7 million to the BP Prudhoe Bay Royalty Trust. These
estimates are reasonable. |
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BP Exploration (Alaska) Inc. estimated that as of December 31, 2005, 1,085.0
million barrels of Proved Reserves have been added to Current Reserves. This estimate
is reasonable. Current Reserves are defined in the Overriding Royalty Conveyance as net
Proved Reserves of 2,035.6 million barrels as of December 31, 1987. Net additions to
Proved Reserves after December 31, 1987 affect the Chargeable Costs that are used to
calculate the Per Barrel Royalty paid to the BP Prudhoe Bay Royalty Trust. |
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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 2012 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. |
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Based on the West Texas Intermediate Price of $61.04 per barrel on December 31,
2005, 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 2023 is reasonable. BP Exploration (Alaska) Inc. expects continued
economic production at a declining rate through the year 2065; however, for the
economic conditions and production forecast as of December 31, 2005 the Per Barrel
Royalty will be zero following the year 2023. Therefore, no reserves are currently
attributed to the BP Prudhoe Bay Royalty Trust after that date. |
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Even if expected reservoir performance does not change, the estimated reserves,
economic life, and future revenues attributable to the BP Prudhoe Bay Royalty Trust may
change significantly in the future. This may result from changes in the West Texas
Intermediate Price or from changes in other prescribed variables utilized in
calculations defined by the Overriding Royalty Conveyance. |
Estimates of ultimate and remaining reserves and production scheduling depend upon assumptions
regarding expansion or implementation of alternative projects or development programs and upon
strategies for production optimization. BP Exploration (Alaska) Inc. has continual reservoir
management, surveillance, and planning efforts dedicated to (1) gathering new information, (2)
improving the accuracy of its reserves and production capacity estimates, (3) recognizing and
exploiting new opportunities, (4) anticipating potential problems and taking corrective actions,
and (5) identifying, selecting, and implementing optimum recovery program and cost reduction
alternatives. Given this
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Miller and Lents, Ltd.
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The Bank of New York
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February 6, 2006 |
Trustee, BP Prudhoe Bay Royalty Trust |
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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 2065. 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 undertaken in the future, BP Exploration (Alaska) Inc. estimates that such sales would
not actually commence until eight to ten years in the future. In the event that major gas sales are
initiated, ultimate oil and condensate recoveries may be reduced from the current estimates unless
recovery projects other than those included in the current estimates are implemented.
Large volumes of natural gas liquids are likely to be produced and marketed in the future
whether or not major gas sales become viable. Natural gas liquids reserves are not included in the
estimates cited herein. The BP Prudhoe Bay Royalty Trust is not entitled to royalty payments from
production or sales of natural gas or natural gas liquids.
The evaluations presented in this report, with the exceptions of those parameters specified by
others, reflect our informed judgments based on accepted standards of professional investigation
but are
subject to those generally recognized uncertainties associated with interpretation of
geological, geophysical, and engineering information. Government policies and market conditions
different from those reflected in this study or disruption of existing transportation routes or
facilities may cause the total quantity of oil or condensate to be recovered, actual production
rates, prices received, or operating and capital costs to vary from those reviewed in this report.
Miller and Lents, Ltd., is an independent oil and gas consulting firm. None of the principals
of this firm have any direct financial interests in BP Exploration (Alaska) Inc. or its parent or
any related
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Miller and Lents, Ltd.
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The Bank of New York
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February 6, 2006 |
Trustee, BP Prudhoe Bay Royalty Trust |
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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.
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Very truly yours, |
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MILLER AND LENTS, LTD. |
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By
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/s/ William P. Koza, P.E.
William P. Koza, P.E.
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[SEAL] |
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Vice President |
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WPK/hsd
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INDUSTRY CONDITIONS AND REGULATIONS
The production of oil and gas in Alaska is affected by many state and federal regulations with
respect to allowable rates of production, marketing, environmental matters and pricing. Future
regulations could change allowable rates of production or the manner in which oil and gas
operations may be lawfully conducted.
In general, BP Alaskas oil and gas activities are subject to existing federal, state and
local laws and regulations relating to health, safety, environmental quality and pollution control.
BP Alaska believes that the equipment and facilities currently being used in its operations
generally comply with the applicable legislation and regulations. During the past few years,
numerous environmental laws and regulations have taken effect at the federal, state and local
levels. Oil and gas operations are subject to extensive federal and state regulation and to
interruption or termination by governmental authorities due to ecological and other considerations
and in certain circumstances impose absolute liability upon lessees for the cost of cleaning up
pollutants and for pollution damages resulting from their operations. Although BP Alaska has
advised that the existence of legislation and regulation has had no material adverse effect on BP
Alaskas current method of operations, existing and future legislation and regulations cannot be
predicted.
CERTAIN TAX CONSIDERATIONS
The following is a summary of the principal tax consequences to Unit holders resulting from
the ownership and disposition of Units. The laws and regulations affecting these matters are
complex, and are subject to change by future legislation or regulations or new interpretations by
the Internal Revenue Service, state taxing authorities or the courts. In addition, there may be
differences of opinion as to the applicability or interpretation of present tax laws and
regulations. BP Alaska and the Trust have not requested any rulings from the Internal Revenue
Service with respect to the tax treatment of the Units, and no assurance can be given that the
Internal Revenue Service would concur with the statements below.
Unit holders are urged to consult their tax advisors regarding the effects on their specific
tax situations of owning and disposing of Units.
Federal Income Tax
Classification of the Trust
The following discussion assumes that the Trust is properly classified as a grantor trust
under current law and is not an association taxable as a corporation.
General Features of Grantor Trust Taxation
A grantor trust is not subject to tax, and its beneficiaries (the Unit holders in the case of
the Trust) are considered for tax purposes to own the assets of the trust directly. The Trust pays
no federal income tax but files an information return reporting all items of income or deduction.
If a court were to hold that the Trust is an association taxable as a corporation, the Trust would
incur substantial income tax liabilities in addition to its other expenses.
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
holders method of accounting. Consequently, it is possible that in any year a Unit holders
share of the
21
taxable income of the Trust may exceed the cash actually distributed to him in that
year. For example, if the Trustee should add to the reserve for the payment of Trust liabilities or
repay money borrowed to satisfy debts of the Trust, the money used to replenish the reserve or to
repay the loan is income to and must be reported by the Unit holder, even though the money was not
distributed to the Unit holder.
The Trust makes quarterly distributions to the persons who held Units of record on each
Quarterly Record Date. The terms of the Trust Agreement seek to assure to the extent practicable
that income, expenses and deductions attributable to each distribution are reportable by the Unit
holder who receives the distribution.
The Trust allocates income and deductions to Unit holders based on record ownership at
Quarterly Record Dates. It is not known whether the Internal Revenue Service will accept the
allocation based on this method.
Depletion Deductions
The owner of an economic interest in producing oil and gas properties is entitled to deduct an
allowance for the greater of cost depletion or (if otherwise allowable) percentage depletion on
each such property. A Unit holders deduction for cost depletion in any year is calculated by
multiplying the holders 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 holders gross income from the Trust rather than on his
adjusted basis in his Units. Any deduction for cost depletion or percentage depletion allowable to
a Unit holder reduces his adjusted basis in his Units for purposes of computing subsequent
depletion or gain or loss on any subsequent disposition of Units.
Unit holders must maintain records of their adjusted basis in their Units, make adjustments
for depletion deductions to such basis, and use the adjusted basis for the computation of gain or
loss on the disposition of the Units.
Taxation of Foreign Unit Holders
Generally, a holder of Units who is a nonresident alien individual or which is a foreign
corporation (a Foreign Taxpayer) is subject to tax 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 provides otherwise or unless the Secretary of the Treasury consents to a
revocation.
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
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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 882 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 28 percent of any reportable payment if the payee fails to furnish his
taxpayer identification number (TIN) to the payor in the required manner or if the Secretary of
the Treasury notifies the payor that the TIN furnished by the payee is incorrect. Unit holders will
avoid backup withholding by furnishing their correct TINs to the Trustee in the form required by
law.
State Income Taxes
Unit holders may be required to report their share of income from the Trust to their state of
residence or commercial domicile. However, only corporate Unit holders will need to report their
share of income to the State of Alaska. Alaska does not impose an income tax on individuals or
estates and trusts. All Trust income is Alaska source income to corporate Unit holders and should
be reported accordingly.
ITEM 2. PROPERTIES
Reference is made to Item 1 for the information required by this item.
ITEM 1A. RISK FACTORS
Owners of Units are exposed to risk and uncertainties that are particular to their investment. This Item describes several, but not necessarily all of them.
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Royalty Production from the Prudhoe Bay field is projected to decline after 2012 and
will eventually cease. |
The Prudhoe Bay field has been in production since 1977. Development of the field is largely
completed, and proved reserves are being depleted. Production of oil and condensate from the field
has been declining during recent years and the decline is expected to continue. BP Alaska has
estimated that net production from current proved reserves allocated to the BP Working Interests
will exceed 90,000
barrels per day until the year 2012. Economic production is expected to continue after 2012,
but at a rate less than 90,000 barrels per day and royalty payments to the Trust are projected to
cease after 2023. The foregoing estimates are based on economic conditions and production forecasts
as of the end of 2005,
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and also depend on various assumptions, projections and estimates which are
continually revised and updated by BP Alaska. These revisions could result in material changes to
the projected declines in production. It is possible that economic production from the reserves
allocated to the BP Working Interests could decline more quickly and end sooner that is currently
projected, especially if natural gas production from the Prudhoe Bay field commences, as discussed
in the following paragraphs.
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Construction of a proposed gas pipeline from the North Slope of Alaska to the Midwestern
United States could accelerate the decline in net royalty production from the Prudhoe Bay
field, result in higher production tax deductions from royalty payments to the Trust, or
both. |
On February 21, 2006 Alaska Governor Frank Murkowski announced that the State and BP Alaska,
ConocoPhilips and Exxon Mobil had reached agreement in principle on a natural gas pipeline contract.
The proposed $20 billion natural gas pipeline would run from Alaskas North Slope through Canada
and into the Midwestern United States and would be completed in six to eight years. The Governor
also announced that he had proposed legislation to reform Alaskas oil production tax. The new
petroleum production tax would replace the current production tax on oil, which is based on a
percentage of the gross value of production. Under the Governors petroleum production tax,
producers will pay a 20 percent tax rate on net profits and will receive a 20 percent tradable
capital investment tax credit and a $73 million standard deduction.
The gas pipeline contract has not been made public and is not final. The Governors production
tax bill has been introduced in both houses of the Alaska Legislature (as SB 305 in the Senate and
as HB 488 in the House), but has not been enacted and may be amended in committee. There could be
significant changes to the pipeline contract and to the petroleum production tax proposed by the
Governor.
At present, extraction of natural gas from the Prudhoe Bay Unit is not economical. Natural gas
released by pumping oil is reinjected into the ground, which helps to maintain reservoir pressure
and facilitates extraction of oil from the fields. If the proposed natural gas pipeline is
constructed, it will make it economical to extract natural gas from the Prudhoe Bay Unit and
transport it to the lower 48 states for sale. Extraction of natural gas from the Prudhoe Bay field
will lower reservoir pressure. The lowering of the reservoir pressure may accelerate the decline in
production from the BP Working Interests and the time at which royalty payments to the Trust will
cease. Since the Trust is not entitled to any royalty payments with respect to natural gas
production from the BP Working Interests, the Unit holders will not realize any offsetting benefit
from the natural gas production.
It is too early to tell what effect the Governors tax proposal, if enacted, will have on the
Production Taxes chargeable against Royalty Production under the Conveyance. The Per Barrel Royalty
payable to the Trust could be reduced if the new petroleum production tax results in an effective
rate of tax chargeable against the Royalty Interest that is higher than the current 15 percent tax
imposed on wellhead value.
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Royalty payments by BP Alaska to the Trust are unpredictable, because they depend
directly on world crude oil prices which have been volatile in recent years. |
During the past decade, crude oil prices have been very volatile. Crude oil prices have
increased continuously since 2001, with the average WTI Price having reached $63 per barrel during
the third quarter of 2005. Before 2002, though, crude oil prices went through a period of extreme
volatility. In late
1998 and early 1999, spot oil prices fell to a historic lows, reaching barely $10 per barrel
in December 1998. As a result, the average WTI Price during the fourth quarter of 1998 and the
first quarter of 1999 fell below the total adjusted Chargeable Costs and Production Taxes
chargeable against Royalty
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Production and the Trust did not receive royalty distributions from BP
Alaska during the first two quarters of 1999.
Recent moves in crude oil prices have been affected by many factors, including changes in
demand by oil-consuming countries, the actions of OPEC to control production by members of the
cartel, shifts in inventory management strategies by international oil companies, increasing
effects of the oil futures market, and other unpredictable political, psychological and economic
factors such as the war in Iraq and tensions with Iran over its nuclear program. Future domestic
and international events and conditions may produce wide swings in crude oil prices over relatively
short periods of time. Unit holders thus are subject to the risk that cash distributions with
respect to their Units may vary widely from quarter to quarter.
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Production from the Prudhoe Bay field could be interrupted by damage to the Trans-Alaska
Pipeline System from natural disasters, accidents, or deliberate attacks. |
The Trans-Alaska Pipeline System connects the North Slope oil fields to the southern port of
Valdez, almost 800 miles away. It is the only way that oil can be transported from the North Slope
to market. The pipeline system crosses three mountain ranges, many rivers and streams and
thaw-sensitive permafrost. It is susceptible along its length to damage from earthquakes, forest
fires and other natural disasters. The pipeline system also is vulnerable to accidental damage and
deliberate attacks. If the pipeline or its pumping stations should suffer major damage from natural
or man-made causes, production from the Prudhoe Bay field could be shut in until the pipeline
system can be repaired and restarted. Royalty payments to the Trust could be reduced by a material
amount as a result of interruption to production from the Prudhoe Bay field.
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Production from the Prudhoe Bay Unit may be interrupted or discontinued by BP Alaska. |
BP Alaska 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 Trust does
not have the right to take over operation of the BP Working Interests or share in any operating
decisions by BP Alaska concerning the Prudhoe Bay Unit. 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, BP Alaska has no
obligation to use insurance proceeds to repair such damage and may elect to retain such proceeds
and close damaged areas to production.
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There are potential conflicts of interest between BP Alaska and the Trust that could
affect the royalties paid to Unit holders. |
The interests of BP Alaska and the Trust with respect to the Prudhoe Bay Unit could at times
be different. The Per Barrel Royalty that BP Alaska pays to the Trust is based on the WTI Price and
Chargeable Costs, both of which are amounts contractually defined the Conveyance. The WTI Price
does not necessarily correspond to the actual price realized by BP Alaska for crude oil produced
from the BP Working Interests, and Chargeable Costs may not bear any relation to BP Alaskas actual
costs of production. The actual per barrel profit realized by BP Alaska on the Royalty Production
may differ materially from the Per Barrel Royalty that it is required to pay to the Trust. It is
possible under certain circumstances that the relationship between BP Alaskas actual per barrel
revenues and costs could be
such that BP Alaska might determine to interrupt or discontinue production in whole or in part
from the BP Working Interests even though a Per Barrel Royalty might otherwise be payable to the
Trust under the Conveyance.
25
ITEM 1B. UNRESOLVED STAFF COMMENTS
The Trust has not received any written comments from the staff of the Securities and Exchange
Commission regarding its periodic or current reports under the Exchange Act that remain unresolved.
ITEM 3. LEGAL PROCEEDINGS
There are no pending legal proceedings to which the Trust is a party or of which any of its
property is the subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of Unit holders during the fourth quarter ended December
31, 2005.
PART II
ITEM 5. MARKET FOR REGISTRANTS UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF
UNITS
The Units are listed and traded on the New York Stock Exchange under the symbol BPT. The
following table shows the high and low sales prices per Unit on the New York Stock Exchange and the
cash distributions paid per Unit, for each calendar quarter in the two years ended December 31,
2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions |
|
|
High |
|
Low |
|
Per Unit |
2004: |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
30.25 |
|
|
$ |
22.50 |
|
|
$ |
0.670 |
|
Second Quarter |
|
|
32.90 |
|
|
|
26.31 |
|
|
|
0.846 |
|
Third Quarter |
|
|
40.00 |
|
|
|
32.13 |
|
|
|
0.998 |
|
Fourth Quarter |
|
|
50.50 |
|
|
|
39.95 |
|
|
|
1.304 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005: |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
70.95 |
|
|
$ |
46.40 |
|
|
$ |
1.544 |
|
Second Quarter |
|
|
75.79 |
|
|
|
56.47 |
|
|
|
1.545 |
|
Third Quarter |
|
|
79.99 |
|
|
|
69.50 |
|
|
|
1.728 |
|
Fourth Quarter |
|
|
79.90 |
|
|
|
60.10 |
|
|
|
2.282 |
|
As of March 10, 2006, 21,400,000 Units were outstanding and were held by 753 holders of
record. No Units were purchased by the Trust or any affiliated purchaser during the year ended
December 31, 2005.
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 BP Working Interests. See THE ROYALTY INTEREST in Item 1.
26
ITEM 6. SELECTED FINANCIAL DATA
The following table presents in summary form selected financial information regarding the
Trust.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2001 |
|
|
|
(in thousands, except per Unit amounts) |
|
Royalty revenues |
|
$ |
152,978 |
|
|
|
82,682 |
|
|
|
55,986 |
|
|
|
33,061 |
|
|
|
59,934 |
|
Interest income |
|
$ |
37 |
|
|
|
11 |
|
|
|
10 |
|
|
|
23 |
|
|
|
70 |
|
Trust administration expenses |
|
$ |
1,097 |
|
|
|
976 |
|
|
|
1,168 |
|
|
|
822 |
|
|
|
724 |
|
Cash earnings |
|
$ |
151,918 |
|
|
|
81,717 |
|
|
|
54,828 |
|
|
|
32,262 |
|
|
|
59,280 |
|
Cash distributions |
|
$ |
151,908 |
|
|
|
81,702 |
|
|
|
54,867 |
|
|
|
32,246 |
|
|
|
59,319 |
|
Cash distributions per unit |
|
$ |
7.098 |
|
|
|
3.818 |
|
|
|
2.564 |
|
|
|
1.507 |
|
|
|
2.772 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2001 |
|
|
|
(dollar amounts in thousands) |
|
Trust Corpus |
|
$ |
10,876 |
|
|
|
12,881 |
|
|
|
14,730 |
|
|
|
16,498 |
|
|
|
18,564 |
|
Total Assets |
|
$ |
11,054 |
|
|
|
13,052 |
|
|
|
15,046 |
|
|
|
17,093 |
|
|
|
19,086 |
|
Units outstanding |
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
21,400,000 |
|
ITEM 7. TRUSTEES DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Liquidity and Capital Resources
The Trust is a passive entity. The Trustees activities are limited to collecting and
distributing the revenues from the Royalty Interest and paying liabilities and expenses of the
Trust. Generally, the Trust has no source of liquidity and no capital resources other than the
revenue attributable to the Royalty Interest that it receives from time to time. See the discussion
under THE ROYALTY INTEREST in Item 1 for a description of the calculation of the Per Barrel
Royalty, and the discussion under THE PRUDHOE BAY UNIT AND FIELD Reserve Estimates and
INDEPENDENT OIL AND GAS CONSULTANTS REPORT in Item 1 for information concerning the estimated
future net revenues of the Trust. However, the Trust Agreement gives the Trustee power to borrow,
establish a cash reserve, or dispose of all or part of the Trust property under limited
circumstances. See the discussion under BUSINESS The Trust in Item 1.
In 1999, due to declines in oil prices during the fourth quarter of 1998 and the first quarter
of 1999 which resulted in the Trust not receiving cash distributions for two quarters, the Trustee
established a $1,000,000 cash reserve to provide liquidity to the Trust during any future periods
in which the Trust does not receive a distribution. The Trustee will draw funds from the cash
reserve account during any quarter in which the quarterly distribution received by the Trust does
not exceed the liabilities and expenses of the
Trust, and will replenish the reserve from future quarterly distributions, if any. The Trustee
anticipates that it will keep this cash reserve program in place until termination of the Trust.
27
Amounts set aside for the cash reserve are invested by the Trustee in U.S. government or
agency securities secured by the full faith and credit of the United States. Interest income
received by the Trust from the investment of the reserve fund is added to the distributions
received from BP Alaska and paid to the Unit holders on each Quarterly Record Date.
Annual
decreases in Trust Corpus and total assets are the result of
amortization of the Royalty Interest. See Notes 2 and 3 of Notes to
Financial Statements in Item 8.
Results of Operations
Relatively modest changes in oil prices significantly affect the Trusts revenues and results
of operations. Crude oil prices are subject to significant changes in response to fluctuations in
the domestic and world supply and demand and other market conditions as well as the world political
situation as it affects OPEC and other producing countries. The effect of changing economic
conditions on the demand and supply for energy throughout the world and future prices of oil cannot
be accurately projected.
Royalty revenues are generally received on the Quarterly Record Date (generally the fifteenth
day of the month) following the end of the calendar quarter in which the related Royalty Production
occurred. The Trustee, to the extent possible, pays all expenses of the Trust for each quarter on
the Quarterly Record Date on which the revenues for the quarter are received. For the statement of
cash earnings and distributions, revenues and Trust expenses are recorded on a cash basis and, as a
result, distributions to Unit holders in each calendar year ending December 31 are attributable to
BP Alaskas operations during the twelve-month period ended on the preceding September 30.
As long as BP Alaskas average daily net production from the BP Working Interests exceeds
90,000 barrels, which BP Alaska currently projects will continue until the year 2012, the only
factors affecting the Trusts revenues and distributions to Unit holders are changes in WTI Prices,
scheduled annual increases in Chargeable Costs, changes in the Consumer Price Index, changes in
Production Taxes, changes in the expenses of the Trust, contributions to the cash reserve and
interest earned on the cash reserve.
During the years 2004 and 2005 and the period of 2006 up to the date of this report, WTI
Prices have been above the level necessary for the Trust to receive a Per Barrel Royalty. Whether
the Trust will be entitled to future distributions during the remainder of 2006 will depend on WTI
Prices prevailing during the remainder of the year.
2005 compared to 2004
Continued increases in world oil prices drove higher WTI Prices in the fourth quarter of 2004
and the first three quarters of 2005 (the period on which calendar 2005 cash basis revenues were
based), which averaged 44% higher during that period than during the twelve months ended September
30, 2004. As a result, royalty revenues during 2005 rose approximately 85% from 2004, and cash
distributions rose approximately 86%. Chargeable Costs per barrel increased from $12.00 to $12.25,
beginning in the first quarter of 2005. The increase in Chargeable Costs, continued increases in
the Cost Adjustment Factor (which produced adjusted Chargeable Costs averaging $18.15 per barrel
during the twelve months ended September 30, 2005) and increases in Production Taxes (which
averaged approximately 52.5% higher during the twelve months ended September 30, 2005 than in the
prior twelve-month period) attenuated the effect of the increase in WTI Prices on the Trusts
revenues in 2005.
2004 compared to 2003
Increases in world oil prices drove higher WTI Prices in the fourth quarter of 2003 and the
first three quarters of 2004 (the period on which calendar 2004 cash basis revenues were based),
which averaged 22% higher during that period than during the twelve months ended September 30,
2003. As a result, royalty revenues during 2004 rose approximately 48% from 2003, and cash
distributions rose
28
approximately 49%. Chargeable Costs per barrel increased from $11.75 to $12.00,
beginning in the first quarter of 2004. The increase in Chargeable Costs, increases in the Cost
Adjustment Factor (which produced adjusted Chargeable Costs averaging $17.22 per barrel during the
twelve months ended September 30, 2004) and increases in Production Taxes (which averaged
approximately 27% higher during the twelve months ended September 30, 2004 than in the prior
twelve-month period) attenuated the effect of the increase in WTI Prices on the Trusts revenues in
2004.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Trust is a passive entity and except for the Trusts ability to borrow money as necessary
to pay liabilities of the Trust that cannot be paid out of cash on hand, the Trust is prohibited
from engaging in borrowing transactions. The Trust periodically holds short-term investments
acquired with funds held by the Trust pending distribution to Unit holders and funds held in
reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of
these investments and limitations on the types of investments which may be held by the Trust, the
Trust is not subject to any material interest rate risk. The Trust does not engage in transactions
in foreign currencies which could expose the Trust or Unit holders to any foreign currency related
market risk or invest in derivative financial instruments. It has no foreign operations and holds
no long-term debt instruments.
29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BP PRUDHOE BAY ROYALTY TRUST
Index To Financial Statements
30
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 (the Trust) as of December 31, 2005 and 2004, 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, 2005. These financial statements are the responsibility of The Bank of
New York, as the Trusts trustee (the Trustee). Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). 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, and 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 were prepared on the
modified cash basis of accounting, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States of America.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the financial position of the Trust as of December 31, 2005 and 2004 and its cash
earnings and distributions and changes in trust corpus for each of the years in the three-year
period ended December 31, 2005 in conformity with the modified cash basis of accounting described
in Note 2.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of the Trusts internal control over financial reporting
as of December 31, 2005, based on criteria established in Internal ControlIntegrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our
report dated March 15, 2006 expressed an unqualified opinion on the trustees assessment of, and
the effective operation of, internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 15, 2006
31
BP Prudhoe Bay Royalty Trust
Statement of Assets, Liabilities and Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements)
(In thousands, except unit data)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty Interest, net (Notes 1, 2 and 3) |
|
$ |
10,043 |
|
|
$ |
12,051 |
|
Cash and cash equivalents (Note 2) |
|
|
1,011 |
|
|
|
1,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
11,054 |
|
|
$ |
13,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Trust Corpus |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued expenses |
|
$ |
178 |
|
|
$ |
171 |
|
|
|
|
|
|
|
|
|
|
Trust Corpus (40,000,000 units of
beneficial interest authorized,
21,400,000 units issued and outstanding |
|
|
10,876 |
|
|
|
12,881 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Trust Corpus |
|
$ |
11,054 |
|
|
$ |
13,052 |
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
32
BP Prudhoe Bay Royalty Trust
Statements of Cash Earnings and Distributions
(Prepared on a modified basis of cash receipts and disbursements)
(In thousands, except unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Royalty revenues |
|
$ |
152,978 |
|
|
$ |
82,682 |
|
|
$ |
55,986 |
|
Interest income |
|
|
37 |
|
|
|
11 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Trust administrative expenses |
|
|
(1,097 |
) |
|
|
(976 |
) |
|
|
(1,168 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
$ |
151,918 |
|
|
$ |
81,717 |
|
|
$ |
54,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions |
|
$ |
151,908 |
|
|
$ |
81,702 |
|
|
$ |
54,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions per unit |
|
$ |
7.098 |
|
|
$ |
3.818 |
|
|
$ |
2.564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units outstanding |
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
33
BP Prudhoe Bay Royalty Trust
Statements of Changes in Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Trust Corpus at beginning of year |
|
$ |
12,881 |
|
|
$ |
14,730 |
|
|
$ |
16,498 |
|
Cash earnings |
|
|
151,918 |
|
|
|
81,717 |
|
|
|
54,828 |
|
Decrease (increase) in accrued expenses |
|
|
(7 |
) |
|
|
145 |
|
|
|
279 |
|
Cash distributions |
|
|
(151,908 |
) |
|
|
(81,702 |
) |
|
|
(54,867 |
) |
Amortization of Royalty Interest |
|
|
(2,008 |
) |
|
|
(2,009 |
) |
|
|
(2,008 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust Corpus at end of year |
|
$ |
10,876 |
|
|
$ |
12,881 |
|
|
$ |
14,730 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
34
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
(1) |
|
Formation of the Trust and Organization |
|
|
|
BP Prudhoe Bay Royalty Trust (the Trust), a grantor trust, was created as a Delaware business
trust pursuant to a Trust Agreement dated February 28, 1989 among the Standard Oil Company
(Standard Oil), BP Exploration (Alaska) Inc. (BP Alaska), The Bank of New York (The
Trustee) and The Bank of New York (Delaware), as co-trustee. Standard Oil and BP Alaska are
indirect wholly owned subsidiaries of the BP 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) of 16.4246% on the lesser of (a) the
first 90,000 barrels of the average actual daily net production of oil and condensate per
quarter or (b) the average actual daily net production of oil and condensate per quarter from BP
Alaskas working interest as of February 28, 1989 in the Prudhoe Bay Field (the
Field),
located on the North Slope of Alaska. Trust Unit holders will remain subject at all times to the
risk that production will be interrupted or discontinued or fall, on average, below 90,000
barrels per day in any quarter. BP has guaranteed the performance of BP Alaska of its payment
obligations with respect to the Royalty Interest. |
|
|
|
Effective January 1, 2000, BP Alaska and all other Prudhoe Bay working interest owners
cross-assigned interests in the Prudhoe Bay Field pursuant to the Prudhoe Bay Unit Alignment
Agreement. BP Alaska retained all rights, obligations, and liabilities associated with the
Trust. |
|
|
|
The trustees of the Trust are The Bank of New York, a New York corporation authorized to do a
banking business, and The Bank of New York (Delaware), a Delaware banking corporation. The Bank
of New York (Delaware) serves as co-trustee in order to satisfy certain requirements of the
Delaware Trust Act. The Bank of New York alone is able to exercise the rights and powers granted
to the Trustee in the Trust Agreement. |
|
|
|
The Per Barrel Royalty in effect for any day is equal to the price of West Texas Intermediate
crude oil (the WTI Price) for that day less scheduled Chargeable Costs (adjusted in certain
situations for inflation) and Production Taxes (based on statutory rates then in existence). |
|
|
|
The Trust is passive, with the Trustee having only such powers as are necessary for the
collection and distribution of revenues, the payment of Trust liabilities, and the protection of
the Royalty Interest. The Trustee, subject to certain conditions, is obligated to establish cash
reserves and borrow funds to pay liabilities of the Trust when they become due. The Trustee may
sell Trust properties only (a) as authorized by a vote of the Trust Unit Holders, (b) when
necessary to provide for the payment of specific liabilities of the Trust then due (subject to
certain conditions) or (c) upon termination of the Trust. Each Trust Unit issued and outstanding
represents an equal undivided share of beneficial interest in the Trust. Royalty payments are
received by the Trust and distributed to Trust Unit holders, net of Trust expenses, in the month
succeeding the end of each calendar quarter. The Trust will terminate upon the first to occur of
the following events: |
|
a. |
|
On or prior to December 31, 2010: upon a vote of Trust Unit Holders of not less than
70% of the outstanding Trust Units. |
35
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
|
b. |
|
After December 31, 2010: (i) upon a vote of Trust Unit Holders of not less than 60% of
the outstanding Trust Units, or (ii) at such time the net revenues from the Royalty
Interest for two successive years commencing after 2010 are less than $1,000,000 per year
(unless the net revenues during such period are materially and adversely affected by
certain events). |
|
|
In order to ensure the Trust has the ability to pay future expenses, the Trust established a
cash reserve account which the Trustee believes is sufficient to pay approximately one years
current and expected liabilities and expenses of the Trust. |
(2) |
|
Basis of Accounting |
|
|
|
The financial statements of the Trust are prepared on a modified cash basis and reflect the
Trusts assets, liabilities, Corpus, earnings, and distributions, as follows: |
|
a. |
|
Revenues are recorded when received (generally within 15 days of the end of the
preceding quarter) and distributions to Trust Unit Holders are recorded when paid. |
|
|
b. |
|
Trust expenses (which include accounting, engineering, legal, and other professional
fees, trustees fees, and out-of-pocket expenses) are recorded on an accrual basis. |
|
|
c. |
|
Cash reserves may be established by the Trustee for certain contingencies that would
not be recorded under generally accepted accounting principles. |
|
|
d. |
|
Amortization of the Royalty Interest is calculated based on the units of production
method. Such amortization is charged directly to the Trust Corpus, and does not affect cash
earnings. The daily rate for amortization per net equivalent barrel of oil for the years
ended December 31, 2005, 2004, and 2003 was $0.37. The Trust evaluates impairment of the
Royalty Interest by comparing the undiscounted cash flows expected to be realized from the
Royalty Interest to the carrying value, pursuant to Statement of Financial Accounting
Standards No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS
144). If the expected future undiscounted cash flows are less than the carrying value, the
Trust recognizes an impairment loss for the difference between the carrying value and the
estimated fair value of the Royalty Interest. |
|
|
While these statements differ from financial statements prepared in accordance with accounting
principles generally accepted in the United States of America, the modified cash basis of
reporting revenues and distributions is considered to be the most meaningful because quarterly
distributions to the Trust Unit Holders are based on net cash receipts. The accompanying
modified cash basis financial statements contain all adjustments necessary to present fairly the
assets, liabilities and Corpus of the Trust as of December 31, 2005 and 2004, and the modified
cash earning and distributions and changes in Trust Corpus for the years ended December 31,
2005, 2004 and 2003. The adjustments are of a normal recurring nature and are, in the opinion of
the Trustee, necessary to fairly present the results of operations. |
|
|
|
As of December 31, 2005 and 2004, cash equivalents which represent the cash reserve consist of
U.S. treasury bills with an initial term of less than three months. |
|
|
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 |
36
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
|
|
environment, financial markets and any other parameters used in determining these
estimates could cause actual results to differ, and the difference could be material. |
(3) |
|
Royalty Interest |
|
|
|
The Royalty Interest is comprised of the following at December 31, 2005 and 2004 (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
Royalty Interest (at inception) |
|
$ |
535,000 |
|
|
$ |
535,000 |
|
Less: Accumulated amortization |
|
|
(351,439 |
) |
|
|
(349,431 |
) |
Impairment write-down |
|
|
(173,518 |
) |
|
|
(173,518 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of period |
|
$ |
10,043 |
|
|
$ |
12,051 |
|
|
|
|
|
|
|
|
(4) |
|
Income Taxes |
|
|
|
The Trust files its federal tax return as a grantor trust subject to the provisions of subpart E
of Part I of Subchapter J of the Internal Revenue Code of 1986, as amended, rather than as an
association taxable as a corporation. The Trust 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 Trust 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 Trusts tax liability as an association. |
(5) |
|
Subsequent Event |
|
|
|
In February 2006 the Governor of Alaska announced that the State and BP Alaska, ConocoPhilips
and ExxonMobil had reached agreement in principle on a natural gas pipeline contract. The
proposed natural gas pipeline would run from Alaskas North Slope through Canada and into the
Midwestern United States and would be completed in six to eight years. The Governor also
announced that he had proposed legislation to reform the states oil production tax. The
proposed oil and gas production tax would replace the current production tax on oil, which is
based on a percentage of the gross value of production. Under the Governors proposed bill,
producers will pay a tax on net profits and will receive a tradable capital investment tax
credit and a standard deduction. The gas pipeline contract is not final or public and the
Governors tax bill has not been enacted by the Alaska legislature. It is not certain that the
pipeline will be constructed or that the petroleum production tax will be enacted in the form
proposed by the Governor. |
|
|
|
If the proposed gas pipeline is constructed, extraction of natural gas from the Field will lower reservoir pressure and may accelerate the decline in production from the
reserve volumes attributable to the Trust and the time at which royalty payments to the Trust
will cease. The Trust is not entitled to any royalty payments with respect to natural gas
production from the Field. |
37
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
|
|
The Per Barrel Royalty payable to the Trust could be reduced if a new Alaska petroleum
production tax results in an effective rate of tax chargeable against the Royalty Interest that
is higher than the current tax imposed on wellhead value of production. |
(6) |
|
Summary of Quarterly Results (Unaudited) |
|
|
|
A summary of selected quarterly financial information for the years ended December 31, 2005,
2004, and 2003 is as follows (in thousands, except unit data): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 Fiscal Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
Royalty revenues |
|
$ |
33,197 |
|
|
|
33,413 |
|
|
|
37,357 |
|
|
|
49,011 |
|
Interest income |
|
|
5 |
|
|
|
9 |
|
|
|
11 |
|
|
|
12 |
|
Trust administrative expenses |
|
|
(151 |
) |
|
|
(367 |
) |
|
|
(388 |
) |
|
|
(191 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
33,051 |
|
|
|
33,055 |
|
|
|
36,980 |
|
|
|
48,832 |
|
Cash distributions |
|
|
33,051 |
|
|
|
33,060 |
|
|
|
36,971 |
|
|
|
48,826 |
|
Cash distributions per unit |
|
|
1.5444 |
|
|
|
1.5449 |
|
|
|
1.7276 |
|
|
|
2.2816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 Fiscal Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
Royalty revenues |
|
$ |
14,659 |
|
|
|
18,342 |
|
|
|
21,566 |
|
|
|
28,115 |
|
Interest income |
|
|
2 |
|
|
|
3 |
|
|
|
2 |
|
|
|
4 |
|
Trust administrative expenses |
|
|
(216 |
) |
|
|
(324 |
) |
|
|
(212 |
) |
|
|
(224 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
14,445 |
|
|
|
18,021 |
|
|
|
21,356 |
|
|
|
27,895 |
|
Cash distributions |
|
|
14,343 |
|
|
|
18,109 |
|
|
|
21,352 |
|
|
|
27,898 |
|
Cash distributions per unit |
|
|
0.6702 |
|
|
|
0.8462 |
|
|
|
0.9978 |
|
|
|
1.3036 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 Fiscal Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
Royalty revenues |
|
$ |
12,538 |
|
|
|
17,722 |
|
|
|
12,147 |
|
|
|
13,579 |
|
Interest income |
|
|
4 |
|
|
|
2 |
|
|
|
2 |
|
|
|
2 |
|
Trust administrative expenses |
|
|
(469 |
) |
|
|
(333 |
) |
|
|
(225 |
) |
|
|
(141 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
12,073 |
|
|
|
17,391 |
|
|
|
11,924 |
|
|
|
13,440 |
|
Cash distributions |
|
|
12,412 |
|
|
|
17,291 |
|
|
|
11,823 |
|
|
|
13,341 |
|
Cash distributions per unit |
|
|
0.580 |
|
|
|
0.808 |
|
|
|
0.553 |
|
|
|
0.623 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Royalty revenues |
|
$ |
152,978 |
|
|
|
82,682 |
|
|
|
55,986 |
|
Interest income |
|
|
37 |
|
|
|
11 |
|
|
|
10 |
|
Trust administrative expenses |
|
|
(1,097 |
) |
|
|
(976 |
) |
|
|
(1,168 |
) |
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
151,918 |
|
|
|
81,702 |
|
|
|
54,828 |
|
Cash distributions |
|
|
151,908 |
|
|
|
81,702 |
|
|
|
54,867 |
|
Cash distributions per unit |
|
|
7.098 |
|
|
|
3.818 |
|
|
|
2.564 |
|
38
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
(7) |
|
Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flow
Relating to Proved Reserves (Unaudited) |
|
|
|
Pursuant to Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas
Producing Activities (FASB 69), the Trust is required to include in its financial statements
supplementary information regarding estimates of quantities of proved reserves attributable to
the Trust and future net cash flows. |
|
|
|
Estimates of proved reserves are inherently imprecise and subjective and are revised over time
as additional data becomes available. Such revisions may often be substantial. Information
regarding estimates of proved reserves attributable to the combined interests of BP Alaska and
the Trust were based on reserve estimates prepared by BP Alaska. BP Alaskas 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 BP Alaska 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, 2005
($61.04 per barrel), December 31, 2004 ($43.46 per barrel) and December 31, 2003 ($32.55 per
barrel). Because the reserve volumes attributable to the Trust are estimated using an allocation
of reserve volumes based on the 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 Trusts 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. Net proved reserves of oil and condensate attributable to the Trust as of December 31,
2005, 2004 and 2003, based on BP Alaskas latest reserve estimate at such time and the WTI Prices
on December 31, 2005, 2004 and 2003, were estimated to be 85, 77 and 78 million barrels,
respectively (of which 73, 68 and 67 million barrels, respectively, are proved developed). Under
the provisions of FASB 69, no consideration can be given to reserves not considered proved at
the present time. |
|
|
|
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 changes 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, 2005, 2004 and 2003, the standardized measure of discounted future net cash flow
relating to proved reserves attributable to the Trust (estimated in accordance with the
provisions of FASB 69), based on the WTI Prices on those dates of $61.04, $43.46 and $32.55,
respectively, were as follows (in thousands): |
39
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Future net cash flows |
|
$ |
2,095,163 |
|
|
$ |
1,130,851 |
|
|
$ |
644,691 |
|
10% annual discount for
estimated timing of cash flows |
|
|
(885,424 |
) |
|
|
(454,532 |
) |
|
|
(249,373 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future
net cash flow relating to proved reserves (a) |
|
$ |
1,209,739 |
|
|
$ |
676,319 |
|
|
$ |
395,318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The following are the principal sources of the change in the standardized measure of
discounted future net cash flows (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Revisions of prior estimates: |
|
|
|
|
|
|
|
|
|
|
|
|
Reserve volumes |
|
$ |
2,472 |
|
|
$ |
6,123 |
|
|
$ |
(3,915 |
) |
WTI price |
|
|
787,204 |
|
|
|
494,363 |
|
|
|
56,270 |
|
Adjusted chargeable costs |
|
|
(33,736 |
) |
|
|
(80,201 |
) |
|
|
(15,712 |
) |
Production taxes |
|
|
(116,558 |
) |
|
|
(72,641 |
) |
|
|
(7,666 |
) |
Other |
|
|
(370 |
) |
|
|
(15 |
) |
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
639,012 |
|
|
|
347,629 |
|
|
|
28,985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income received (b) |
|
|
(173,224 |
) |
|
|
(106,160 |
) |
|
|
(60,943 |
) |
Accretion of discount |
|
|
67,632 |
|
|
|
39,532 |
|
|
|
38,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase during the year |
|
$ |
533,420 |
|
|
$ |
281,001 |
|
|
$ |
6,885 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) |
|
For the purpose of this calculation, royalty income received for 2005, 2004 and 2003
includes the following: |
|
|
|
|
|
Period October 1, 2005 through December 31, 2005 |
|
$ |
45,246 |
|
Period October 1, 2004 through December 31, 2004 |
|
$ |
33,197 |
|
Period October 1, 2003 through December 31, 2003 |
|
$ |
14,659 |
|
The above royalty income was received by the Trust in January 2006, 2005 and 2004, respectively.
40
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
The changes in quantities of proved oil and condensate were as follows (in thousands of barrels):
|
|
|
|
|
Estimated net proved reserves of oil and condensate at December 31, 2003 |
|
|
77,942 |
|
Production |
|
|
(5,410 |
) |
Reserve estimate revisions |
|
|
635 |
|
Change caused by prices/costs |
|
|
4,237 |
|
|
|
|
|
|
|
|
|
|
Estimated net proved reserves of oil and condensate at December 31, 2004 |
|
|
77,404 |
|
Production |
|
|
(5,395 |
) |
Reserve estimate revisions |
|
|
(1,711 |
) |
Change caused by prices/costs |
|
|
15,015 |
|
|
|
|
|
|
|
|
|
|
Estimated net proved reserves of oil and condensate at December 31, 2005 |
|
|
85,313 |
|
|
|
|
|
|
|
|
|
|
Proved reserves: |
|
|
|
|
|
|
|
|
|
December 31, 2003 |
|
|
77,942 |
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
77,404 |
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
85,313 |
|
|
|
|
|
41
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There have been no changes in accountants and no disagreements with accountants on any matter
of accounting principles or practices or financial statement disclosures during the two fiscal
years ended December 31, 2005.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
The Trustee has disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule
15d-15(e) under the Exchange Act) that are designed to ensure that information required to be
disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of
1934, as amended (the Exchange Act) is recorded, processed, summarized and reported, within the
time periods specified in the SECs rules and forms. These controls and procedures include but are
not limited to controls and procedures designed to ensure that information required to be disclosed
by the Trust in the reports that it files or submits under the Exchange Act is accumulated and
communicated to the responsible trust officers of the Trustee to allow timely decisions regarding
required disclosure.
Under the terms of the Trust Agreement and the Conveyance, BP Alaska has significant
disclosure and reporting obligations to the Trust. BP Alaska is required to provide the Trust such
information concerning the Royalty Interest as the Trustee may need and to which BP Alaska has
access to permit the Trust to comply with any reporting or disclosure obligations of the Trust
pursuant to applicable law and the requirements of any stock exchange on which the Units are
issued. These reporting obligations include furnishing the Trust a report by February 28 of each
year containing all information of a nature, of a standard and in a form consistent with the
requirements of the SEC respecting the inclusion of reserve and reserve valuation information in
filings under the Exchange Act and with applicable accounting rules. The report is required to set
forth, among other things, BP Alaskas estimates of future net cash flows from proved reserves
attributable to the Royalty Interest, the discounted present value of such proved reserves, the
assumptions utilized in arriving at the estimates contained in the report, and the estimate of the
quantities of proved reserves (including reductions of proved reserves as a result of modification
of BP Alaskas estimates of proved reserves from prior years) added during the preceding year to
the total proved reserves allocated to the BP Working Interests as of December 31, 1987. (See THE
ROYALTY INTEREST Chargeable Costs in Item 1.)
In addition, the Conveyance gives the Trust and its independent accountants certain rights to
inspect the books and records of BP Alaska and discuss the affairs, finances and accounts of BP
Alaska relating to the BP Working Interests with representatives of BP Alaska; it also requires BP
Alaska to provide the Trust with such other information as the Trustee may reasonably request from
time to time and to which BP Alaska has access.
The Trustees disclosure controls and procedures include ensuring that the Trust receives the
information and reports that BP Alaska is required to furnish to the Trust on a timely basis, that
the appropriate responsible personnel of the Trustee examine such information and reports, and that
information requested from and provided by BP Alaska is included in the reports that the Trust
files or submits under the Exchange Act.
As of the end of calendar 2005, the trust officers of the Trustee responsible for the
administration of the Trust conducted an evaluation of the Trusts disclosure controls and
procedures. Their evaluation
42
considered, among other things, that the Trust Agreement and the
Conveyance impose enforceable legal obligations on BP Alaska, and that BP Alaska has provided the
information required by those agreements and other information requested by the Trustee from time
to time on a timely basis. The officers concluded that the Trusts disclosure controls and
procedures are effective.
Internal Control Over Financial Reporting
Managements Annual Report on Internal Control Over Financial Reporting. The Bank of New York,
as Trustee of the Trust, is responsible for establishing and maintaining adequate internal control
over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange
Act. The Trustee conducted an evaluation of the effectiveness of the Trusts internal control over
financial reporting based on the criteria established in Internal ControlIntegrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO
criteria). Based on the Trustees evaluation under the COSO criteria, the Trustee concluded that
the Trusts internal control over financial reporting was effective as of December 31, 2005.
The Trustees assessment of the effectiveness of the Trusts internal control over financial
reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public
accounting firm, as stated in their report set forth in full below.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Trustee and Holders of Trust Units of BP Prudhoe Bay Royalty Trust:
We have audited the trustees assessment, included in the Trustees Report on Internal Control over
Financial Reporting under Item 9A of the accompanying Annual Report on Form 10-K, that BP Prudhoe
Bay Royalty Trust (the Trust) maintained effective internal control over financial reporting as
of December 31, 2005, based on criteria established in Internal ControlIntegrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of BP
Prudhoe Bay Royalty Trust is responsible for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on the trustees assessment and an opinion on the
effectiveness of the Trusts internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating the trustees assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinion.
A trusts internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with the modified cash basis of accounting. A
trusts internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of
the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with the modified cash basis of accounting, and
that receipts and expenditures of the trust are being made only in accordance with authorizations
of the
43
trustee; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the trusts assets that could have a material
effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the trustees assessment that BP Prudhoe Bay Royalty Trust maintained effective
internal control over financial reporting as of December 31, 2005, is fairly stated, in all
material respects, based on criteria established in Internal ControlIntegrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion,
BP Prudhoe Bay Royalty Trust maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2005, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the statements of assets, liabilities and trust corpus of BP Prudhoe Bay
Royalty Trust as of December 31, 2005 and 2004, 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, 2005, and our report dated March 15, 2006 expressed an unqualified opinion on those
financial statements and included an explanatory paragraph that described the Trusts method of
accounting as explained in Note 2 to the financial statements.
KPMG LLP
Dallas, Texas
March 15, 2006
Changes in Internal Control Over Financial Reporting. There has not been any change in the
Trusts internal control over financial reporting identified in connection with the Trustees
evaluation of the Trusts internal control over financial reporting that occurred during the
Trusts fourth fiscal quarter that has materially affected, or is reasonably likely to materially
affect, the Trusts internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
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.
44
ITEM 11. EXECUTIVE COMPENSATION
The Trust has no directors, officers or employees to whom it pays compensation. The Trust is
administered by employees of the Trustee in the ordinary course of their employment by the Trustee
and receive no compensation specifically related to their services to the Trust.
The compensation received by the Trustee from the Trust during the three fiscal years ended
December 31, 2005 was as follows:
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Transfer Agent and |
|
|
|
|
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Registrar |
Year ended December 31, |
|
Trustees Fees |
|
Fees |
2005 |
|
$ |
141,288 |
|
|
$ |
7,075 |
|
2004 |
|
|
116,378 |
|
|
|
6,647 |
|
2003 |
|
|
114,572 |
|
|
|
7,381 |
|
Under the Trust Agreement, the Trustee is entitled to receive on each Quarterly Record Date a
quarterly fee consisting of: (i) a quarterly administrative fee of $.0011 per Unit outstanding on
the Quarterly Record Date and (ii) a transfer service fee of $1.50 per Unit holder account as of
the Quarterly Record Date. Both the administrative service fee and the transfer service fee are
subject to increase by the proportionate increase, if any, during the preceding calendar year in
the Consumer Price Index during the preceding calendar year. The Trustee also bills the Trust for
certain reimbursable expenses.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Securities Authorized for Issuance under Equity Compensation Plans
No Units are authorized for issuance under any form of equity compensation plan.
Unit Ownership of Certain Beneficial Owners
As of March 16, 2006, there were no persons known to the Trustee to be the beneficial owners
of more than five percent of the Units.
Unit Ownership of Management
Neither BP Alaska, 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.
45
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees for services performed by KPMG LLP for the years ended December 31, 2005 and 2004 are:
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|
|
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|
|
|
|
2005 |
|
|
2004 |
|
Audit |
|
|
113,000 |
|
|
$ |
108,000 |
|
Audit related |
|
|
16,000 |
|
|
|
14,500 |
|
Tax |
|
|
200,000 |
|
|
|
200,000 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
329,000 |
|
|
$ |
322,500 |
|
|
|
|
|
|
|
|
The Trust has no audit committee, and as a consequence, has no audit committee pre-approval
policy with respect to fees paid to KPMG LLP.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) FINANCIAL STATEMENTS
The following financial statements of the Trust are included in Part II, Item 8:
|
Report of Independent Registered Public Accounting Firm |
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2005 and 2004 |
Statements of Cash Earnings and Distributions for the years ended December 31, 2005, 2004 and 2003 |
Statements of Changes in Trust Corpus for the years ended December 31, 2005, 2004 and 2003 |
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. |
|
31 |
|
Rule 13a-14(a) certification. |
|
32 |
|
Section 1350 certification. |
46
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.
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BP PRUDHOE BAY ROYALTY TRUST |
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By:
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THE BANK OF NEW YORK, as Trustee |
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By:
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/s/ Ming J. Ryan
Ming J. Ryan
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Vice President |
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|
March 16, 2006
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.
47
INDEX TO EXHIBITS
|
|
|
Exhibit No. |
|
Description |
4.1*
|
|
BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil
Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson,
Co-Trustee. |
|
|
|
4.2*
|
|
Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc.
and The Standard Oil Company. |
|
|
|
4.3*
|
|
Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay
Royalty Trust. |
|
|
|
4.4*
|
|
Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c.,
BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust. |
|
|
|
31
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|
Rule 13a-14(a) certification. Filed herewith |
|
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|
32
|
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Section 1350 certification. Filed herewith. |
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* |
|
Incorporated by reference to the correspondingly numbered exhibit to the Registrants
Annual Report on Form 10-K for the fiscal year ended December 31, 1996 (File No. 1-10243). |