BP PRUDHOE BAY ROYALTY TRUST 10-K/A
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Amendment No. 1)
|
|
|
þ |
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year ended December 31, 2007
OR
|
|
|
o |
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 1-10243
BP PRUDHOE BAY ROYALTY TRUST
(Exact name of registrant as specified in its charter)
|
|
|
DELAWARE
State or other jurisdiction
of incorporation or organization)
|
|
13-6943724
(I.R.S. Employer Identification No.) |
|
|
|
THE BANK OF NEW YORK, TRUSTEE
101 BARCLAY STREET
NEW YORK, NEW YORK
(Address of principal executive offices)
|
|
10286
(Zip Code) |
Registrants telephone number, including area code: (212) 815-6908
Securities registered pursuant to Section 12(b) of the Act:
|
|
|
Title of Each Class |
|
Name of Each Exchange on Which Registered |
UNITS OF BENEFICIAL INTEREST
|
|
NEW YORK STOCK EXCHANGE |
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark 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,
a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in
Rule 12b-2 of the Exchange Act. (Check one):
|
|
|
|
|
|
|
Large accelerated filer þ
|
|
Accelerated filer o
|
|
Non-accelerated filer o
|
|
Smaller reporting company o |
|
|
(Do not check if a smaller reporting company) |
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 29, 2007 (the last business day
of the registrants most recently completed second fiscal quarter) was approximately
$1,545,508,000.
As
of February 28, 2008, 21,400,000 Units of Beneficial Interest were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
Explanatory Note
This
Amendment No. 1 on Form 10-K/A (this Form 10-K/A) amends the Trusts annual report for the
fiscal year ended December 31, 2007, originally filed with the Securities and Exchange Commission
(SEC) on February 29, 2008 (the Form
10-K). This Form 10-K/A is being filed as a result of
reclassification of certain amounts included in the fees reported to have been received by the
Trustee from the Trust during the year ended December 31, 2007 in Part III, Item 11 Executive
Compensation in order to make the fees comparable to fees
reported for prior periods. No other corrections are being made to the Form 10-K, but for the convenience of the
reader this Form 10-K/A amends and restates in its entirety the previously filed Form 10-K.
This Form 10-K/A continues to speak as of the date of the Form 10-K, and no disclosures in the
original Form 10-K have been modified or updated except as noted above. Information not affected by
the amendment contained in this Form 10-K/A is unchanged and reflects the disclosure made at the
time of the filing of the Form 10-K with the SEC. In particular, any forward-looking statements
included in this Form 10-K/A represent the Trustees view as of the filing date of the Form 10-K.
TABLE OF CONTENTS
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
1 |
|
|
|
|
2 |
|
|
|
|
6 |
|
|
|
|
12 |
|
|
|
|
13 |
|
|
|
|
14 |
|
|
|
|
20 |
|
|
|
|
25 |
|
|
|
|
25 |
|
|
|
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
30 |
|
|
|
|
|
|
|
|
|
30 |
|
|
|
|
|
|
|
|
|
30 |
|
|
|
|
|
|
|
|
|
31 |
|
|
|
|
|
|
|
|
|
31 |
|
|
|
|
|
|
|
|
|
31 |
|
|
|
|
|
|
|
|
|
32 |
|
|
|
|
|
|
|
|
|
32 |
|
|
|
|
|
|
|
|
|
34 |
|
|
|
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
|
|
48 |
|
|
|
|
|
|
|
|
|
48 |
|
|
|
|
|
|
|
|
|
50 |
|
|
|
|
|
|
|
|
|
50 |
|
|
|
|
|
|
|
|
|
50 |
|
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 (BNYM (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: remo.reale@bnymellon.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 turn out 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% of the lesser of (i) the first 90,000 barrels* of the
average actual daily net production of crude 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 or (ii) the average actual daily net production of crude oil and condensate per
quarter from that working interest. 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. BNYM (Delaware) (successor to The Bank of New York (Delaware)) has been appointed
co-trustee in order to satisfy the Delaware Statutory Trust Acts requirement that the Trust have
at least one trustee resident in, or which has its principal place of business in, Delaware.
However, 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 with the SEC as an exhibit
to this report.
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 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 that the Trust
normally incurs in the conduct of its
|
|
|
* |
|
The term barrel is a unit of measure of petroleum
liquids equal to 42 United States gallons corrected to 60 degrees Fahrenheit
temperature. |
2
operations 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.
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 Royalty Interest; Borrowings and Reserves
With certain exceptions, the Trustee may sell all or part of the Royalty Interest or an
interest therein only if authorized to do so by vote of the holders of 70% of the Units outstanding
if the sale is to be effected on or before December 31, 2010, or holders of 60% of the Units
outstanding if the sale is to be effected after 2010. 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 and the Trustee has determined that it is not
practical to pay such liabilities out of funds anticipated to be available in subsequent
quarters and that, without such borrowing, the Trust property is subject 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 selected by the Trustee) 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 selected by the
Trustee) 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 in subsequent quarters and
that, in the absence of a
3
reserve, the Trust 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 contemplated 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.
The Trustee maintains a $1,000,000 cash reserve to provide liquidity to the Trust during any
periods in which the Trust does not receive a distribution from BP Alaska. See Item 7 in Part II
below.
Irrevocability; Amendment of the Trust Agreement
The Trust Agreement and the Trust are irrevocable. No person has the power to terminate,
revoke or change the Trust Agreement except as described in the following paragraph and below under
Termination of the Trust.
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 does not adversely affect the Unit holders. The Trust Agreement also may 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% of
the outstanding Units, nor may any amendment reduce or delay the distributions to the Unit holders,
alter the voting rights of Unit holders or the number of Units in the Trust, or make certain other
changes, unless approved by the affirmative vote of holders of at least 80% of the outstanding
Units and by the Trustee. The Trustee is required to consent to any amendment approved by the
requisite vote of Unit holders unless the amendment affects the Trustees rights, duties and
immunities under the Trust Agreement. 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.
Termination of the Trust
The Trust will terminate: (i) on or before December 31, 2010 if holders of at least 70% of the
outstanding Units vote to terminate the Trust, or (ii) after December 31, 2010 if either (a)
holders of at least 60% of the outstanding Units vote to terminate the Trust or (b) 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 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
4
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% of the Units outstanding (60% 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 property on terms
and conditions approved by the vote of holders of 70% of the outstanding Units (60% 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 of the investment banking firm,
commercial banking firm or other entity mentioned above and on terms and conditions deemed
commercially reasonable by that firm.
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.
Unit holders do not have the right under the Trust Agreement to seek or secure any partition
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.
Resignation or Removal of Trustee
The Trustee may resign at any time or be removed with or without cause by vote of the holders
of a majority of the outstanding Units at a meeting called and held in accordance with the Trust
Agreement. A successor trustee may be appointed by BP Alaska or, if the Trustee has been removed at
a meeting of the Unit holders, the successor trustee may be appointed by the Unit holders at the
meeting. Any successor trustee 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.
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 by the Trustee (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% of the
outstanding Units or (ii) when required by applicable laws or regulations or the New York Stock
Exchange. The Trustee will give written notice of any meeting stating the time and place of the
meeting and the matters to be acted on not more than 60 days nor fewer than 10 days before the
meeting to all Unit holders of record on a date not
5
more than 60 days before the meeting at their
addresses shown on the records of the Trust. All meetings of Unit holders are required to be held
in Manhattan, New York City. Unit holders are entitled to cast one vote on all matters coming
before a meeting, in person or by proxy, for each Unit held on the record date for the meeting.
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% of the lesser of (i)
the first 90,000 barrels of the actual average daily net production of crude oil and condensate for
the quarter from the Prudhoe Bay (Permo-Triassic) Reservoir and saved and allocated to the oil and
gas leases owned by BP Alaska in the Prudhoe Bay field as of February 28, 1989 (the BP Working
Interests), or (ii) the actual average daily net production of crude oil and condensate for the
quarter from 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 Intermediate) quoted for that trading day by whichever of The
Wall Street Journal, Reuters, or Platts Oilgram Price Report, in that order, publishes West Texas
Intermediate price quotations for the trading day, or (ii) if the price of West Texas Intermediate
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 Intermediate 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 Intermediate are not quoted so as to permit the calculation of the WTI Price, the price of
West Texas Intermediate, 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.
6
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
production. Chargeable Costs per barrel were $11.75 during 2003, $12.00 during 2004, $12.25 during
2005, $12.50 during 2006 and $12.75 during 2007. Chargeable Costs for 2008 and subsequent years are
shown in the following table:
|
|
|
|
|
|
|
Calendar |
|
Chargeable Costs |
|
Calendar |
|
Chargeable Costs |
year |
|
per barrel |
|
year |
|
per barrel |
|
|
|
|
|
|
|
2008 |
|
$13.00 |
|
2015 |
|
$17.00 |
2009 |
|
13.25 |
|
2016 |
|
17.10 |
2010 |
|
14.50 |
|
2017 |
|
17.20 |
2011 |
|
16.60 |
|
2018 |
|
20.00 |
2012 |
|
16.70 |
|
2019 |
|
23.75 |
2013 |
|
16.80 |
|
2020 |
|
26.50 |
2014 |
|
16.90 |
|
|
|
|
After 2020, Chargeable Costs increase at a uniform rate of $2.75 per barrel 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.
Until August 2006, the Production Taxes payable with respect to the Royalty Production were
(i) the Alaska Oil Production Tax (the Old Tax), which was levied at the flat rate of 15% of the
gross value of oil at the point of production (the wellhead or field value) and which, as required
by the Conveyance, was applied for the purpose of determining the Royalty Interest without regard
to the economic limit factor (a formula designed to result in low tax rates for smaller low
productive fields and higher tax rates for larger highly productive fields), and (ii) a surcharge
of $0.03 per barrel of Royalty Production. The Conveyance provides that, in the case of taxes based
upon wellhead or field value, the WTI Price less the product of $4.50 multiplied by the Cost
Adjustment Factor is deemed to be the wellhead or field value.
Alaska adopted a new oil and gas production tax on August 20, 2006 (Chapter 2, Third Special
Session Laws of Alaska 2006) (the 2006 Tax) which amended the Alaska oil and gas production tax
7
statutes, AS 43.55.10 et seq. (the Production Tax Statutes) and replaced the Old Tax. Under the
2006 Tax, producers were taxed on the production tax value of taxable oil (gross value at the
point of production for the calendar year less the producers direct costs of exploring for,
developing, or producing oil or gas deposits located within the producers leases or properties in
Alaska (Lease Expenditures) for the year) at a rate equal to the sum of 22.5% plus a
progressivity rate determined by the average monthly production tax value of the oil produced.
The progressivity portion of the 2006 Tax was equal to 0.25% times the amount by which the simple
average for each calendar month of the daily production tax values per barrel of the oil produced
during the month exceeded $40 per barrel. In addition, the 2006 Tax increased the surcharge on oil
produced from leases or properties in Alaska from $0.03 to $0.04 per barrel.
On December 19, 2007, Alaska Governor Sarah Palin signed into law a bill (Chapter 1, Second
Special Session Laws of Alaska 2007) (the 2007 Tax) which took effect on December 20, 2007 and
further amended the Production Tax Statutes in certain respects. The 2007 Tax changes the basic tax
rate from 22.5% to 25% and increases the progressivity rate. If the producers average monthly
production tax value per barrel is greater than $30 but not more than $92.50, the new progressivity
tax rate is 0.4% times the amount by which the average monthly production tax value exceeds $30 per
barrel. If the producers average monthly production tax value per barrel is greater than $92.50,
the progressivity tax rate is the sum of 25% and the product of 0.1% multiplied by the difference
between the average monthly production tax value per barrel and $92.50, except that the sum may not
exceed 50%.
In order to resolve uncertainties in the interpretation of the Conveyance resulting from
adoption of the 2006 Tax, in October 2006 the Trustee entered into a letter agreement with BP
Alaska (the 2006 Letter Agreement), a copy of which is incorporated by reference as Exhibit 4.5
to this report. The 2006 Letter Agreement sets forth principles agreed to by BP Alaska and the
Trustee to resolve how the amount of tax chargeable against the Royalty Interest was to be
determined under the Conveyance and the extent to which the retroactivity of the tax legislation
was to be recognized for purposes of the Conveyance (the Consensus Principles). In December 2007,
BP Alaska notified the Trustee that the adoption of the 2007 Tax made it necessary to modify the
Consensus Principles to give effect to the new tax rates. After determining that the proposed
changes to the Consensus Principles were consistent with the changes in tax rates effected by the
2007 Tax, on January 11, 2008 the Trustee executed a letter agreement dated December 21, 2007 with
BP Alaska (the 2008 Letter Agreement) which supplements and amends the 2006 Letter Agreement and
which is incorporated by reference as Exhibit 4.6.to this report.
Determination of Production Taxes
The following paragraphs describe how the Consensus Principles provide for the amount of
Production Taxes (other than the $0.04 per barrel surcharge) to be determined under the 2006 Tax
(from August 20, 2006 through December 19, 2007) and under the 2007 Tax (from December 20, 2007 and
thereafter):
|
(a) |
|
The production tax value per barrel of oil for each day is determined by
taking the WTI Price for that day and subtracting the product of the amount of
the Chargeable Costs then in effect multiplied by the applicable Cost
Adjustment Factor. |
8
|
(b) |
|
The tax rate for the progressivity portion of the tax equals: |
|
|
|
2006 Tax |
|
2007 Tax |
|
|
|
(i) zero, if the simple
average of the daily
taxable values per barrel
under (a) above for a
calendar month is not
greater than $40 per
barrel; or
|
|
(i) zero, if the simple average of
the daily taxable values per barrel
under (a) above for a calendar month
is not greater than $30 per barrel; |
|
|
|
(ii) 0.25% times the amount
by which the simple average
for each calendar month of
the daily production tax
values per barrel of oil
under (a) above, exceeds
$40 per barrel.
|
|
(ii) 0.4% times the amount by which
the simple average of the taxable
values per barrel under (a) above
for a calendar month exceeds $30 per
barrel if that average is not
greater than $92.50 per barrel; or |
|
|
|
|
|
(iii) the sum of 25% plus 0.1% times
the amount by which the simple
average of the taxable values per
barrel under (a) above for a
calendar month exceeds $92.50,
except that such sum may not exceed
50%. |
|
(c) |
|
The amount of Production Tax chargeable against the Royalty Interest equals
the taxable value per barrel under (a) above times the Royalty Production under
the Conveyance, times a rate equal to the sum of the progressivity rate
determined under (b) above plus the following percentage: |
|
|
|
2006 Tax |
|
2007 Tax |
|
|
|
22.5%
|
|
25% |
Retroactivity of Tax
Although both the 2006 Tax and the 2007 Tax are retroactive (to April 1, 2006, in the case of
the 2006 Tax; to July 1, 2007, in the case of the 2007 Tax), in the Consensus Principles the
parties agreed that the 2006 Tax and 2007 Tax would not be applied retroactively to payments by BP
Alaska with respect to the Royalty Interest. Production Taxes charged against the Royalty Interest
were the amount of Old Tax as calculated under the Conveyance for oil production during the period
from April 1 to August 19, 2006, inclusive. For oil produced on August 20, 2006 through December
19, 2007, the Production Taxes charged against the Royalty Interest were the amount of 2006 Tax,
determined as described above, for that production, and for oil produced on December 20, 2007 and thereafter the Production
Taxes charged against the Royalty Interest are the amount of 2007 Tax, determined as described
above.
9
Use of Inflation Adjusted Chargeable Costs under Consensus Principles
The 2006 Letter Agreement contains a discussion of the rationale for using inflation adjusted
Chargeable Costs as a proxy for BP Alaskas actual Lease Expenditures for purposes of determining
Production Taxes chargeable against the Royalty Interest. The 2006 Letter Agreement explains that
under the 2006 Tax BP Alaska is required to use estimates of Lease Expenditures for purposes of its
monthly reporting to the State of Alaska, and that actual Lease Expenditures are determined and
reconciled to monthly estimates up to three months after the close of each fiscal year. The use of
BP Alaskas estimated Lease Expenditures for purposes of calculating the Production Taxes applied
to quarterly payments of the Royalty Interest could require regular adjustments to future royalty
payments to compensate for over or under charges of Production Taxes to past royalty payments once
actual Lease Expenditures were determined. These adjustments could create unfair benefits for
certain Unit holders and unfair detriment to others. BP Alaska stated that inflation adjusted
Chargeable Costs were expected to provide a reasonable, although not an exact, approximation of BP
Alaskas Leasehold Expenditures and provide certainty to investors in the Trust Units. BP Alaska
cautioned, however, that to the extent actual Lease Expenditures for a particular year are higher
than adjusted Chargeable Costs for the year, the Trust Units may bear Production Taxes at a higher
rate than the rate of tax applicable to BP Alaskas production for the year; conversely, if BP
Alaskas Lease Expenditures for a year are less than adjusted Chargeable Costs for that year,
Production Taxes charged against the Royalty Interest may be charged at a lower rate than the rate
of tax applicable to BP Alaskas production.
In addition to changes in the rates of tax applicable to oil and gas production introduced by
the 2007 Tax, the legislation authorizes the Alaska Department of Revenue (DOR) to interpret and
apply the amendments to the Production Tax Statutes. The 2007 Tax allows DOR to limit deductible
transportation costs for transportation by a regulated pipeline to something less than the tariff
actually paid. Other amendments allow DOR to exclude by regulation certain categories of otherwise
deductible lease expenditures, or a fixed percentage of them, from being deductible in determining
the production tax value of taxable oil. In the 2008 Letter Agreement, BP Alaska indicated that,
depending on what the new regulations provide, it may wish to amend the Consensus Principles so
that something less than the full amount of Chargeable Costs is to be deducted under the Conveyance
in determining the taxable value per barrel. Any such amendment would require the consent of the
Trustee. If any such amendment should be proposed, the Trustee will evaluate the proposal to
determine whether such amendment is consistent with the Conveyance and the interests of the Unit
holders of the Trust and will make its decision accordingly.
10
Per Barrel Royalty Calculations
The following table shows how the above-described factors interacted during the past five
years to produce the average Per Barrel Royalty paid during the calendar years indicated. Royalty
revenues are generally received on the fifteenth day of the month following the end of the calendar
quarter in which the related Royalty Production occurred. Revenues and expenses presented in the
statement of cash earnings and distributions presented in Part II, Item 8 below are recorded on a
modified cash basis and, as a result, royalty revenues and distributions shown in such statements
for any calendar year are attributable to BP Alaskas operations during the twelve-month period
ended September 30 of that year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost |
|
Adjusted |
|
|
|
|
|
Average Per |
|
|
Average |
|
Chargeable |
|
Adjustment |
|
Chargeable |
|
Production |
|
Barrel |
|
|
WTI Price |
|
Costs |
|
Factor |
|
Costs |
|
Taxes(1) |
|
Royalty(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar 2003: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Qtr 2002 |
|
|
$28.25 |
|
|
|
$11.25 |
|
|
|
1.396 |
|
|
|
$15.70 |
|
|
|
$ 3.33 |
|
|
|
$ 9.22 |
|
1st Qtr 2003 |
|
|
34.08 |
|
|
|
11.75 |
|
|
|
1.410 |
|
|
|
16.57 |
|
|
|
4.19 |
|
|
|
13.32 |
|
2nd Qtr 2003 |
|
|
29.07 |
|
|
|
11.75 |
|
|
|
1.413 |
|
|
|
16.60 |
|
|
|
3.44 |
|
|
|
9.03 |
|
3rd Qtr 2003 |
|
|
30.30 |
|
|
|
11.75 |
|
|
|
1.421 |
|
|
|
16.70 |
|
|
|
3.62 |
|
|
|
9.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar 2004: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Qtr 2003 |
|
|
31.23 |
|
|
|
11.75 |
|
|
|
1.421 |
|
|
|
16.69 |
|
|
|
3.76 |
|
|
|
10.78 |
|
1st Qtr 2004 |
|
|
35.18 |
|
|
|
12.00 |
|
|
|
1.434 |
|
|
|
17.20 |
|
|
|
4.34 |
|
|
|
13.64 |
|
2nd Qtr 2004 |
|
|
38.31 |
|
|
|
12.00 |
|
|
|
1.456 |
|
|
|
17.47 |
|
|
|
4.79 |
|
|
|
16.05 |
|
3rd Qtr 2004 |
|
|
43.78 |
|
|
|
12.00 |
|
|
|
1.459 |
|
|
|
17.51 |
|
|
|
5.61 |
|
|
|
20.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar 2005: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Qtr 2004 |
|
|
48.35 |
|
|
|
12.00 |
|
|
|
1.471 |
|
|
|
17.65 |
|
|
|
6.29 |
|
|
|
24.41 |
|
1st Qtr 2005 |
|
|
49.70 |
|
|
|
12.25 |
|
|
|
1.477 |
|
|
|
18.09 |
|
|
|
6.49 |
|
|
|
25.12 |
|
2nd Qtr 2005 |
|
|
53.09 |
|
|
|
12.25 |
|
|
|
1.497 |
|
|
|
18.34 |
|
|
|
6.98 |
|
|
|
27.77 |
|
3rd Qtr 2005 |
|
|
63.03 |
|
|
|
12.25 |
|
|
|
1.512 |
|
|
|
18.53 |
|
|
|
8.46 |
|
|
|
36.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar 2006: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Qtr 2005 |
|
|
60.01 |
|
|
|
12.25 |
|
|
|
1.521 |
|
|
|
18.63 |
|
|
|
8.01 |
|
|
|
33.37 |
|
1st Qtr 2006 |
|
|
63.36 |
|
|
|
12.50 |
|
|
|
1.530 |
|
|
|
19.13 |
|
|
|
8.50 |
|
|
|
35.73 |
|
2nd Qtr 2006 |
|
|
70.53 |
|
|
|
12.50 |
|
|
|
1.559 |
|
|
|
19.49 |
|
|
|
9.56 |
|
|
|
41.48 |
|
3rd Qtr 2006 |
|
|
70.64 |
|
|
|
12.50 |
|
|
|
1.570 |
|
|
|
19.63 |
|
|
|
10.68 |
|
|
|
40.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Qtr 2006 |
|
|
60.17 |
|
|
|
12.50 |
|
|
|
1.552 |
|
|
|
19.39 |
|
|
|
9.31 |
|
|
|
31.46 |
|
1st Qtr 2007 |
|
|
58.17 |
|
|
|
12.75 |
|
|
|
1.567 |
|
|
|
19.98 |
|
|
|
8.66 |
|
|
|
29.54 |
|
2nd Qtr 2007 |
|
|
65.00 |
|
|
|
12.75 |
|
|
|
1.601 |
|
|
|
20.42 |
|
|
|
10.59 |
|
|
|
34.00 |
|
3rd Qtr 2007 |
|
|
75.29 |
|
|
|
12.75 |
|
|
|
1.601 |
|
|
|
20.42 |
|
|
|
14.45 |
|
|
|
40.42 |
|
|
|
|
(1) |
|
Production Taxes for the third quarter of 2006 and subsequent quarters reflect the effect of
the 2006 Alaska oil and gas production tax and the application of the Consensus Principles
described above. The 2007 Tax commenced affecting the royalty payment with respect to the
fourth quarter of 2007 which the Trust received in January 2008. |
|
(2) |
|
Average per barrel royalty is calculated on the basis of the following preliminary estimates
of average daily net production of oil and condensate from the BP Working Interests: 62,087
barrels in the third |
11
|
|
|
|
|
quarter of 2006, 87,221 barrels in the fourth quarter of 2006, 86,917 barrels in the
second quarter of 2007 and 81,259 barrels in the third quarter of 2007; average per barrel
royalty for all other periods is calculated on the basis of 90,000 barrels of average daily net
production. See THE PRUDHOE BAY UNIT AND FIELD Collection and Transportation of Prudhoe Bay
Oil and Note 8 of Notes to Financial Statements in Part II,
Item 8 below for additional information. |
|
(3) |
|
Dollar amounts in the table have been rounded to two decimal places for presentation and do
not reflect the precision of the actual calculations. |
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.
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 to Unit holders 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 secured by Government
Obligations with banks having capital, surplus and undivided profits of $100,000,000 or more (which
may include The Bank of New York). 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.
12
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 redeem any Units not so transferred
within 90 days after the end of the 30-day period specified in the notice for a cash price 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 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 BP receives notice from the Trustee that the
royalty payable with respect to the Royalty Interest or any other amount payable by BP Alaska or
Standard Oil has not been paid to the Trustee, BP will cause BP Alaska and Standard Oil to satisfy
their respective payment obligations to the Trust and the Trustee under the Trust Agreement and the
Conveyance, including contributing to BP Alaska the funds necessary to make such payments. BP is
required to make available to BP Alaska and Standard Oil such financial support as BP Alaska,
Standard Oil or the Trustee may request in writing. Any Unit holder has the unconditional right to
institute suit against BP to enforce BPs obligations under the Support Agreement.
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.
13
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 with respect to the Royalty Interest and under the Trust Agreement and the
Conveyance are performed.
BP will be released from its obligation under the Support Agreement upon the sale or transfer
of all or substantially all of 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).
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 several contiguous oil fields, the Prudhoe Bay Unit was established to optimize field
development. Other owners of these fields include affiliates of Exxon Mobil Corporation,
ConocoPhillips and ChevronTexaco Corporation. The Trusts Royalty Interest pertains only to
production from the BP Working Interests in the Prudhoe Bay field and does not include production
from the other oil fields included in the Prudhoe Bay Unit.
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, 2007 is shown
in the following table:
|
|
|
|
|
|
|
|
|
|
|
Oil rim |
|
|
Gas cap |
|
|
|
|
|
|
|
|
|
|
BP Alaska |
|
|
26.36 |
%(a) |
|
|
26.36 |
%(b) |
Exxon Mobil |
|
|
36.40 |
|
|
|
36.40 |
|
ConocoPhillips |
|
|
36.08 |
|
|
|
36.08 |
|
ChevronTexaco |
|
|
1.16 |
|
|
|
1.16 |
|
|
|
|
|
|
|
|
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% as of February 28, 1989. Subsequent decreases
in BP |
14
|
|
|
|
|
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% 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 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 the BP Working Interests 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 the BP Working Interests, 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, 2007, approximately 11 billion barrels of oil and condensate had
been produced from the Prudhoe Bay field.
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.
15
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.
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 on a large scale) 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 (TAPS). As of December 31, 2007 there were about 1,126 active
producing oil wells, 34 gas reinjection wells, 86 water injection wells and 133 water and miscible
gas injection wells in the Prudhoe Bay field. Production from the Prudhoe Bay field reached a peak
in 1988 and has declined steadily since then. The average well production rate was about 350
barrels per day in 2003, 317 barrels per day in 2004, 293 barrels per day in 2005, 223 barrels per
day in 2006 and 232 barrels per day in 2007. There was a temporary
impact on production from the
east side of the Prudhoe Bay Unit as a result of the August 2006 partial shutdown, as discussed in
the last paragraph under the heading Collection and Transportation of Prudhoe Bay Oil, below
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 |
Calendar |
|
|
|
|
|
Net to BP Working |
|
|
|
|
|
Net to BP Working |
year |
|
Total field |
|
Interests |
|
Total field |
|
Interests |
|
|
(thousand barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
2006(a) |
|
|
173.9 |
|
|
|
77.1 |
|
|
|
76.7 |
|
|
|
9.3 |
|
2007(b) |
|
|
181.6 |
|
|
|
80.5 |
|
|
|
80.4 |
|
|
|
9.7 |
|
|
|
|
(a) |
|
2006 production figures reported in the Trusts Annual Report on Form 10-K for the year ended December 31, 2006 have been revised to reflect actual production for the year. |
|
(b) |
|
2007 production figures are estimated by BP Alaska based on the best available data. |
16
Collection and Transportation of Prudhoe Bay Oil
Raw crude oil produced from individual production wells located at well pads is diverted to
flowlines (pipelines). The flowlines transport the raw crude oil to one of six separation
facilities (three on the western side of the Prudhoe Bay Unit and three on the eastern side) where
the water and natural gas mixed with the raw crude are removed. The stabilized crude is then sent from the separation
facilities through two 34-inch diameter transit lines, one from each half of the Prudhoe Bay Unit,
to Pump Station 1, the starting point for TAPS.
At Pump Station 1, Alyeska Pipeline Service Company, the operator of TAPS, 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 from the Prudhoe Bay Unit to Valdez. TAPS has a capacity of approximately 1.4
million barrels of oil per day.
On August 7, 2006, BP announced that BP Alaska had begun a shutdown of the Prudhoe Bay Unit
following the discovery of unexpectedly severe corrosion and a small spill from the oil transit
line on the eastern side of the field. The decision followed the receipt several days earlier of
data from a smart pig run completed in late July. Analysis of the data revealed 16
anomalies in 12 locations in the oil transit line. During follow up inspections of the anomalies,
BP Alaska personnel discovered corrosion-related wall thinning which appeared to exceed criteria
for continued operation and a leak and small spill estimated at four to five barrels. BP had
previously announced plans to replace a three-mile segment of transit line on the western side of
the Prudhoe Bay field following inspections conducted after a large spill caused by corrosion
discovered in March 2006.
BP subsequently determined to shut down only the eastern side of the Prudhoe Bay Unit and
continue production from the western side of the Unit. The partial shutdown of the field reduced
average daily production to approximately half of normal output. On September 22, 2006, BP
announced that it had received clearance from the U.S. Department of Transportation (DOT) to
restart production in the eastern half of the Prudhoe Bay Unit. BP has announced plans to
completely replace approximately 16 miles of transit lines and to implement federally-required
corrosion monitoring practices. Replacement of the transit lines commenced in 2007 and will
continue into 2008. BP Alaska has implemented the new DOT federally required corrosion monitoring
practices, which supplement or replace corrosion monitoring practices that existed prior to the new
DOT corrosion monitoring requirements.
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.
|
|
|
|
|
An electronic device including magnetic flux leakage
and ultrasonic thickness testing systems that is propelled through a pipeline
to inspect the pipeline wall. |
17
Reserve Estimates
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 Alaskas reserve
estimates and production assumptions and projections are predicated upon a reasonable estimate of
the allocation of hydrocarbon liquids between oil and condensate according to the procedures of the
Prudhoe Bay Unit Operating Agreement. 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, 2007 were 97.8 million
barrels of oil and condensate, of which 86.87 million barrels are proved developed reserves and
10.93 million barrels are proved undeveloped reserves. Using procedures specified in Financial
Accounting Standards Board Statement of Financial Accounting Standards No. 69, BP Alaska calculated that as of
December 31, 2007 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 $3,209.3
million, with a present value of $1,599.8 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.
BP Alaska has undertaken a program of field-wide infrastructure renewal, pipeline replacement,
and mechanical improvements to wells. As a consequence of these activities and their required
downtime, BP Alaskas net production of oil and condensate from proved reserves was less than
90,000 barrels per day on an annual basis in 2007. BP Alaska anticipates that its average net
production of oil and condensate from proved reserves will be below 90,000 barrels per day on an
annual average basis in 2008 and all future years. The occurrence of major gas sales could
accelerate the decline in net production, due to the consequent decline in reservoir pressure. See
Item 1A, RISK FACTORS. Based on the WTI Price of $96.01 per barrel on December 31, 2007, current
Production Taxes, and the Chargeable Costs adjusted as prescribed by the Overriding Royalty
Conveyance, it is estimated that royalty payments to the Trust will continue through the year 2031.
BP Alaska expects continued economic production from the Prudhoe Bay field at a declining rate
through 2075.
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 BP Working Interests. 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 BP Working Interests based on WTI Prices and other economic
parameters in effect on the date of the evaluation.
The following table shows the net remaining proved reserves of oil and condensate allocated to
the BP Working Interests, the net proved reserves allocated to the Trust, and the WTI Prices on the
dates indicated:
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved Reserves |
|
|
|
|
BP Working |
|
|
|
|
|
WTI Price |
December 31 |
|
Interests (a) |
|
Trust (b) |
|
per barrel |
|
|
(million barrels) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
858.7 |
|
|
|
77.9 |
|
|
$ |
32.55 |
|
2004 |
|
|
941.4 |
|
|
|
77.4 |
|
|
|
43.46 |
|
2005 |
|
|
1,043.0 |
|
|
|
85.3 |
|
|
|
61.04 |
|
2006 |
|
|
912.1 |
|
|
|
81.1 |
|
|
|
61.06 |
|
2007 |
|
|
915.1 |
|
|
|
97.8 |
|
|
|
96.01 |
|
|
|
|
(a) |
|
Includes proved undeveloped reserves of 139.9 million barrels at December 31, 2003,
115.4 million barrels at December 31, 2004, 96.0 million barrels at December 31, 2005, 84.2
million barrels at December 31, 2006 and 68.7 million barrels at December 31, 2007. |
|
(b) |
|
Includes proved undeveloped reserves of 11.0 million barrels at December 31, 2003, 9.1
million barrels at December 31, 2004, 12.3 million barrels at December 31, 2005, 12.1
million barrels at December 31, 2006 and 10.9 million barrels at December 31, 2007. |
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 changes to the procedure for calculating Production
Taxes. 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 11 (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. The Prudhoe Bay Unit working interest
owners regularly assess the technical and economic attractiveness of implementing projects to
increase Prudhoe Bay Unit proved reserves. See Item 1A, RISK FACTORS, below.
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.
19
INDEPENDENT OIL AND GAS CONSULTANTS REPORT
Miller and Lents, Ltd.
international oil and gas consultants
founded 1948
February 11, 2008
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street, 8 West
New York, New York 10286
|
|
|
Re:
|
|
Estimates of Proved Reserves, |
|
|
Future Production Rates, and |
|
|
Future Net Revenues for the |
|
|
BP Prudhoe Bay Royalty Trust
|
|
|
As of December 31, 2007 |
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, 2007. 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 were summarized in the report prepared by BP
Exploration (Alaska) Inc. and transmitted with a cover letter dated February 5th, 2008 addressed to
Mr. Remo Reale of The Bank of New York and signed by Mr. Lewis Westwick. 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.
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.
20
Miller and Lents, Ltd.
|
|
|
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
|
|
February 11, 2008 |
The Prudhoe Bay (Permo-Triassic) Reservoir is defined in the Prudhoe Bay Unit Operating
Agreement. The Prudhoe Bay Unit is an oil and gas unit situated on the North Slope of Alaska. The
BP Prudhoe Bay Royalty Trust is entitled to a royalty payment on 16.4246 percent of the first
90,000 barrels of the actual average daily net production of oil and condensate for each calendar
quarter from the BP Exploration (Alaska) Inc. working interest as defined in the Overriding Royalty
Conveyance. The payment amount depends upon the Per Barrel Royalty which in turn depends upon the
West Texas Intermediate Price, the Chargeable Costs, the Cost Adjustment Factor, and Production
Taxes, all of which are defined in the Overriding Royalty Conveyance. Barrel as used herein means
Stock Tank Barrel as defined in the Overriding Royalty Conveyance.
Our reviews do not constitute independent estimates of the reserves and annual production rate
forecasts for the areas, pay zones, projects, and recovery processes examined. We relied upon the
accuracy and completeness of information provided by BP Exploration (Alaska) Inc. with respect to
pertinent ownership interests and various other historical, accounting, engineering, and geological
data.
As a result of our cumulative reviews, based on the foregoing, we conclude that:
|
1. |
|
A large body of basic data and detailed analyses are available and were used in
making the estimates. In our judgment, the quantity and quality of currently available
data on reservoir boundaries, original fluid contacts, and reservoir rock and fluid
properties are sufficient to indicate that any future revisions to the estimates of
total original in-place volumes should be minor. Furthermore, the data and analyses on
recovery factors and future production rates are sufficient to support the Proved
Reserves estimates. |
|
|
2. |
|
The methods and procedures employed to accumulate and evaluate the necessary
information and to estimate, document, and reconcile reserves, annual production rate
forecasts, and future net revenues are effective and are in accordance with generally
accepted geological and engineering practice in the petroleum industry. |
|
|
3. |
|
Based on our limited independent tests of the computations of reserves,
production flowstreams, and future net revenues, such computations were performed in
accordance with the methods and procedures described to us. |
|
|
4. |
|
The estimated net remaining Proved Reserves attributable to the BP Prudhoe Bay
Royalty Trust as of December 31, 2007, of 97.80 million barrels of oil and condensate
are, in the aggregate, reasonable. Of the 97.80 million barrels of total Proved
Reserves, 86.87 million barrels are Proved Developed Reserves, and 10.93 million
barrels are Proved Undeveloped Reserves. |
|
|
5. |
|
Utilizing the specified procedures outlined in Financial Accounting Standards
Board Statement of Financial Accounting Standards No. 69, BP Exploration (Alaska) Inc.
calculated that as of December 31, 2007 production of the Proved Reserves will result
in Estimated Future Net Revenues of $3,209.3 million and Present Value of Estimated
Future Net Revenues of $1,599.8 million to the BP Prudhoe Bay Royalty Trust. These
estimates are reasonable. |
|
|
6. |
|
BP Exploration (Alaska) Inc. has undertaken a program of field-wide
infrastructure renewal, pipeline replacement, and well mechanical improvements. As a
consequence of these activities and their required downtime, BP Exploration (Alaska)
Inc.s net production of oil and condensate from Proved Reserves was less than 90,000
barrels per |
21
Miller and Lents, Ltd.
|
|
|
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
|
|
February 11, 2008 |
|
|
|
day on an annual average basis in 2007. BP Exploration (Alaska) Inc. expects that
its net production of oil and condensate from Proved Reserves will be less than 90,000
barrels per day on an annual average basis in all future years. The BP Exploration
(Alaska) Inc. projection of its net production of oil and condensate under its forecast
of downtime and operating efficiency is reasonable. |
|
|
7. |
|
Production attributable to the BP Prudhoe Bay Royalty Trust will decline with
the BP Exploration (Alaska) Inc. production. However, the Per Barrel Royalty will not
have a positive value if the West Texas Intermediate Price is less than the sum of the
per barrel Chargeable Costs and per barrel Production Taxes, appropriately adjusted in
accordance with the Overriding Royalty Conveyance. Under such circumstances, average
daily production attributable to the BP Prudhoe Bay Royalty Trust will have no value
and therefore will not contribute to the reserves regardless of BP Exploration (Alaska)
Inc.s net production level. |
|
|
8. |
|
Based on the West Texas Intermediate Price of $96.01 per barrel on December 31,
2007, 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 2031 is reasonable. BP Exploration (Alaska) Inc. expects continued
economic production at a declining rate through the year 2075; however, for the
economic conditions and production forecast as of December 31, 2007 the Per Barrel
Royalty will be zero following the year 2031. Therefore, no reserves are currently
attributed to the BP Prudhoe Bay Royalty Trust after that date. |
|
|
9. |
|
Even if expected reservoir performance does not change, the estimated reserves,
economic life, and future revenues attributable to the BP Prudhoe Bay Royalty Trust may
change significantly in the future. This may result from changes in the West Texas
Intermediate Price or from changes in other prescribed variables utilized in
calculations defined by the Overriding Royalty Conveyance. |
Estimates of ultimate and remaining reserves and production scheduling depend upon assumptions
regarding expansion or implementation of alternative projects or development programs and upon
strategies for production optimization. BP Exploration (Alaska) Inc. has continual reservoir
management, surveillance, and planning efforts dedicated to (1) gathering new information, (2)
improving the accuracy of its reserves and production capacity estimates, (3) recognizing and
exploiting new opportunities, (4) anticipating potential problems and taking corrective actions,
and (5) identifying, selecting, and implementing optimum recovery program and cost reduction
alternatives. Given this significant effort and ever-changing economic conditions, estimates of
reserves and production profiles will change periodically.
The current estimate of Proved Reserves includes only those projects or development programs
that are deemed reasonably certain to be implemented, given current economic and regulatory
conditions. Future projects, development programs, or operating strategies different from those
assumed in the
current estimates may change future estimates and affect recoveries. However, because several
complementary and alternative projects are being considered for recovery of the remaining oil in
the reservoir, a decision not to implement a currently planned project may allow scope expansion or
implementation of another project, thereby increasing the overall likelihood of recovering the
reserves.
Future production rates will be controlled by facilities limitations and upsets, well
downtime, and the effectiveness of programs to optimize production and costs. BP Exploration
(Alaska) Inc. currently
22
Miller and Lents, Ltd.
|
|
|
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
|
|
February 11, 2008 |
expects continued economic production from the reservoir at a declining rate through the year
2075. 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
anticipated 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 ten to eleven 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.
23
Miller and Lents, Ltd.
|
|
|
The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
|
|
February 11, 2008 |
Miller and Lents, Ltd., is an independent oil and gas consulting firm. None of the principals
of this firm have any direct financial interests in BP Exploration (Alaska) Inc. or its parent or
any related companies or in the BP Prudhoe Bay Royalty Trust. Our fee is not contingent upon the
results of our work or report, and we have not performed other services for BP Exploration (Alaska)
Inc. or the BP Prudhoe Bay Royalty Trust that would affect our objectivity.
|
|
|
|
|
|
Very truly yours,
MILLER AND LENTS, LTD.
|
|
|
By: |
/s/ William P. Koza, P.E.
|
[Seal] |
|
|
William P. Koza, P.E. |
|
|
|
Vice President
|
|
|
WPK/eb
24
INDUSTRY CONDITIONS AND REGULATIONS
The production of oil and gas in Alaska is affected by many state and federal regulations with
respect to allowable rates of production, marketing, environmental matters and pricing. Future
regulations could change allowable rates of production or the manner in which oil and gas
operations may be lawfully conducted.
In general, 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, the effect of future legislation and regulations cannot be
predicted.
Since the end of 2006, the oil transit lines in the Prudhoe Bay field have been subject to
federal supervision and inspection by the U.S. Department of Transportation under the Pipeline
Inspection, Protection, Enforcement and Safety Act of 2006. See THE PRUDHOE BAY UNIT AND FIELD
Collection and Transportation of Prudhoe Bay Oil above.
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.
25
Taxation of Unit Holders
In computing his federal income tax liability, each Unit holder is required to take into
account his share of all items of Trust income, gain, loss, deduction, credit and tax preference,
based on the Unit holders method of accounting. Consequently, it is possible that in any year a
Unit holders share of the taxable income of the Trust may exceed the cash actually distributed to
him in that year. For example, if the Trustee should 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% (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
26
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 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 Taxpayer is a corporation which made an election under Internal Revenue Code
section 882(d), the corporation would also be subject to a 30% 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% 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 1A. RISK FACTORS
Owners of Units are exposed to risks and uncertainties that are particular to their
investment. This Item describes several such risks and uncertainties, but not necessarily all of
them.
|
|
|
Royalty Production from the Prudhoe Bay field is projected to decline 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
27
been declining during recent years and the decline is expected to continue. Royalty payments to
the Trust are projected to cease after 2031. Production estimates included in this report are based
on economic conditions and production forecasts as of the end of 2007, 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 than is currently projected, especially if construction of a
gas pipeline makes it economical to produce natural gas from the
Prudhoe Bay field on a large scale, as discussed
below.
|
|
|
Construction of a proposed gas pipeline from the North Slope of Alaska to the Midwestern
United States could accelerate the decline in Royalty Production from the Prudhoe Bay
field. |
In June 2006, the Alaska legislature passed, and Governor Sarah Palin signed, the Alaska
Gasline Inducement Act (AGIA), a law designed to advance construction of a natural gas pipeline
from the North Slope to the lower 48 states. The AGIA requires a prospective pipeline project
builder to meet certain requirements that will advance the project in exchange for a license that
provides up to $500 million in matching funds. On January 4, 2008, Governor Palin announced that
the State had finished its completeness review of the five applications submitted under the AGIA,
and that the application from two subsidiaries of Calgary-based TransCanada Corporation
(TransCanada) satisfied all of the mandatory requirements set out in the AGIA. TransCanadas
application states that it anticipates that construction of the pipeline would begin in 2015, and
that commercial operation would begin by November 2017. The TransCanada application will be subject
to public comment until March 6, 2008, after which the commissioners of Natural Resources and
Revenue (the Commissioners) will review the comments submitted and issue written findings and a
recommendation for or against issuing the AGIA license. If the Commissioners recommend issuance of
the license, their findings will be forwarded to the Alaska legislature, which has 60 days to pass
a bill approving the issuance of the license.
It is not certain that TransCanada will be granted a license to construct the proposed
pipeline or that the pipeline will be constructed or, if constructed, that it will be completed on
the proposed schedule. ConocoPhillips has submitted a competing gas pipeline plan outside of the
AGIA requirements.
Without a pipeline, extraction of natural gas from the Prudhoe Bay field on a large scale 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 field. If a natural gas
pipeline is constructed, it will make it economical to extract natural gas from the Prudhoe Bay
field and transport it to the lower 48 states for sale. Extraction of natural gas from the Prudhoe
Bay field will lower reservoir pressure, although carbon dioxide stripped out of the gas can be
reinjected and other methods can be employed to mitigate the reduction. 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 natural gas production from the Prudhoe Bay
field.
|
|
|
Royalty Production from the Prudhoe Bay field may be adversely affected by the recent
change in the Alaska Production Tax Statutes. |
The recent enactment of the 2007 Tax (see THE ROYALTY INTEREST Production Taxes in Item 1
above) may accelerate the decline in production of oil and condensate from the Prudhoe Bay field if
BP Alaska and the other owners of working interests in the Prudhoe
Bay Unit significantly reduce or defer investment in oil production infrastructure renewal, well
development and implementation of new technology. The 2007 Tax, in addition to increasing the basic
oil production tax rate and the progressivity factor, also eliminates
or reduce many deductions
and credits
28
permitted under the 2006 Tax. BP Alaska has announced that its 2008 capital budget of
$800 million is $100 million less than it would have spent under the 2006 Tax regime. BP Alaska
stated that the total actual reduction in 2008 industry investment in
the Prudhoe Bay Unit by all
working interest owners is about $400 million.
|
|
|
Royalty payments by BP Alaska to the Trust are unpredictable, because they depend on Cushing, Oklahoma WTI spot prices, which have been volatile in recent years, and on the volume of production from the BP Working Interests, which may vary from quarter to quarter in the future. |
Even
though WTI Prices have been rising generally in recent years, they nevertheless remain subject to significant periodic
fluctuations. For additional information, see the monthly history of WTI Prices since 1986 published by the U.S. Energy Information Administration at http://tonto.eia.doe.gov/dnav/pet/hist/rwtcM.htm.
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, conservation measures by consumers, increasing effects of the oil futures market,
and other unpredictable political, psychological and economic factors. Future domestic and international events and conditions may produce wide swings in crude oil prices over relatively short periods of time.
Moreover, it is increasingly likely that the Trust's revenues in future periods also will be affected by increases and decreases in production from the BP Working Interests. BP Alaska's net production of oil and condensate from proved reserves in the BP Working Interests was less than 90,000 barrels per day on an annual basis during 2007.
The Trustee has been advised that BP Alaska expects that average net production from the BP Working Interests will be less than 90,000 barrels a day on an annual basis in 2008 and future years. Unit holders thus are subject to the risk that cash distributions with respect to their Units may vary widely from quarter to quarter.
|
|
|
Prudhoe Bay field oil production could be shut in partially or entirely from time to
time as a result of damage to or failures of field pipelines or equipment. |
In August 2006, BP Alaska shut down the eastern side of the Prudhoe Bay Unit following the
discovery of unexpectedly severe corrosion and a small spill from the oil transit line on that side
of the Unit. Earlier, in March of 2006, BP had to temporarily shut down and commence the replacement of a
three-mile segment of transit line on the western side of the Prudhoe Bay Unit following discovery
of a large oil spill.
BP
has announced plans to completely replace approximately 16 miles of
transit lines and has implemented federally-required corrosion monitoring practices. However, the discovery of additional
defects in Prudhoe Bay Unit oil flowlines and transit lines, and damage to or failures of
separation facilities or other critical equipment, could result in future shutdowns of oil
production from all or portions of the Prudhoe Bay Unit and have an adverse effect on future
royalty payments.
29
|
|
|
Oil production from the Prudhoe Bay Unit 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 failures of pipeline
segments and pumping equipment, 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 Unit could be shut in until the pipeline system can be repaired and restarted. Royalty
payments to the Trust could be halted or reduced by a material amount as a result of interruption
to production from the Prudhoe Bay Unit.
|
|
|
Production from the BP Working Interests may be interrupted or discontinued by BP
Alaska. |
BP Alaska has no obligation to continue production from the BP Working Interests 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 infrastructure, facilities and equipment in the Prudhoe Bay
field 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.
|
|
|
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,
Chargeable Costs and Production Taxes, all 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 and Production Taxes may
not bear any relation to BP Alaskas actual costs of production and tax expenses. 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.
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 2. PROPERTIES
Reference is made to Item 1 for the information required by this item.
ITEM 3. LEGAL PROCEEDINGS
None
30
|
|
|
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, 2007.
PART II
|
|
|
ITEM 5. |
|
MARKET FOR REGISTRANTS UNITS, RELATED UNITHOLDER 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,
2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions |
|
|
High |
|
Low |
|
Per Unit |
2006: |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
72.99 |
|
|
$ |
64.26 |
|
|
$ |
2.114 |
|
Second Quarter |
|
|
80.00 |
|
|
|
67.05 |
|
|
|
2.208 |
|
Third Quarter |
|
|
91.50 |
|
|
|
66.34 |
|
|
|
2.595 |
|
Fourth Quarter |
|
|
77.49 |
|
|
|
69.75 |
|
|
|
1.675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007: |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
76.98 |
|
|
|
54.80 |
|
|
|
1.544 |
|
Second Quarter |
|
|
72.50 |
|
|
|
63.50 |
|
|
|
1.545 |
|
Third Quarter |
|
|
79.40 |
|
|
|
64.50 |
|
|
|
1.728 |
|
Fourth Quarter |
|
|
80.20 |
|
|
|
69.20 |
|
|
|
2.282 |
|
As
of February 26, 2008, 21,400,000 Units were outstanding
and were held by 647 holders of
record. No Units were purchased by the Trust or any affiliated purchaser during the year ended
December 31, 2007.
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 Royalty Production from the BP Working Interests. See THE ROYALTY INTEREST
in Item 1.
31
|
|
|
ITEM 6. |
|
SELECTED FINANCIAL DATA |
The following table presents in summary form selected financial information regarding the
Trust.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(in thousands, except per Unit amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty revenues |
|
$ |
177,318 |
|
|
|
184,864 |
|
|
|
152,978 |
|
|
|
82,682 |
|
|
|
55,986 |
|
Interest income |
|
$ |
81 |
|
|
|
75 |
|
|
|
37 |
|
|
|
11 |
|
|
|
10 |
|
Trust administration expenses |
|
$ |
1,687 |
|
|
|
1,057 |
|
|
|
1,097 |
|
|
|
976 |
|
|
|
1,168 |
|
Cash earnings |
|
$ |
175,712 |
|
|
|
183,882 |
|
|
|
151,918 |
|
|
|
81,717 |
|
|
|
54,828 |
|
Cash distributions |
|
$ |
175,713 |
|
|
|
183,883 |
|
|
|
151,908 |
|
|
|
81,702 |
|
|
|
54,867 |
|
Cash distributions per unit |
|
$ |
8.211 |
|
|
|
8.593 |
|
|
|
7.098 |
|
|
|
3.818 |
|
|
|
2.564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(dollar amounts in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust corpus |
|
$ |
6,592 |
|
|
|
8,853 |
|
|
|
10,876 |
|
|
|
12,881 |
|
|
|
14,730 |
|
Total assets |
|
$ |
7,035 |
|
|
|
9,044 |
|
|
|
11,054 |
|
|
|
13,052 |
|
|
|
15,046 |
|
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 THE TRUST Sales of Royalty Interest; Borrowings and
Reserves in Item 1.
Since 1999, the Trustee has maintained 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.
32
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.
When BP Alaskas average net production of oil and condensate per quarter from the BP Working
Interests exceeds 90,000 barrels a day, the principal 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 and changes in Production Taxes. However, it is
increasingly likely that the Trusts revenues in future periods also will be affected by increases
and decreases in production from the BP Working Interests. BP Alaskas net production of oil and
condensate from proved reserves in the BP Working Interests was less than 90,000 barrels per day on
an annual basis during 2007. The Trustee has been advised that BP Alaska expects that average net
production from the BP Working Interests will be less than 90,000 barrels a day on an annual basis
in 2008 and future years.
BP Alaska estimates Royalty Production from the BP Working Interests for purposes of
calculating quarterly royalty payments to the Trust because complete actual field production data
for the preceding calendar quarter generally is not available by the Quarterly Record Date. To the
extent that average net production from the BP Working Interests is below 90,000 barrels per day,
calculation by BP Alaska of actual Royalty Production data may result in revisions of prior Royalty
Production estimates. Revisions by BP Alaska of its Royalty Production calculations may result in
quarterly royalty payments by BP Alaska which reflect adjustments for overpayments or underpayments
of royalties with respect to prior quarters. Such adjustments, if material, may adversely affect
certain Unit holders who buy or sell Units between the Quarterly Record Dates for the Quarterly
Distributions affected. See Note 8 of Notes to Financial Statements in Item 8. Because the annual
statement of cash earnings and distributions of the Trust is prepared on a modified cash basis,
royalty revenues for the calendar year do not include the amounts of underpayments or overpayments
affecting payments received during the fourth quarter of the year.
During the years 2006 and 2007 and the period of 2008 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
33
be entitled to future distributions during the remainder of 2008 will depend on WTI Prices
prevailing during the remainder of the year.
2007 compared to 2006
World oil prices and WTI Prices receded during the fourth quarter of 2006 and first quarter of
2007 from the highs reached during the second and third quarters of 2006. As a consequence, in
spite of average WTI Prices having risen to an all-time high of $75.29 during the third quarter of
2007, average WTI Prices for the twelve months ended September 30, 2007 were 2.2% lower than during
the preceding twelve-month period. Royalty revenues and cash earnings fell 4.1% and 4.4%,
respectively, partly as a result of the overall decline in WTI Prices, but were affected to a
greater degree by the higher tax rates imposed by the 2006 Alaska oil and gas tax legislation,
which entered into the calculation of the Per Barrel Royalty commencing in the third quarter of
2006 (see THE ROYALTY INTEREST Production Taxes in Item 1), as well as by a scheduled increase
in Chargeable Costs from $12.50 to $12.75 per barrel beginning in the first quarter of 2007.
Production taxes charged against the average Per Barrel Royalty were approximately 17% higher with
respect to the twelve months ended September 30, 2007 than during the twelve months ended September
30, 2006. Cash earnings were affected by an increase of approximately 60% in Trust administrative
expenses, principally due to legal fees and expenses incurred defending a class action lawsuit. See
Note 7 of Notes to Financial Statements in Item 8.
2006 compared to 2005
Increases in world oil prices drove WTI Prices higher in the fourth quarter of 2005 and the
first three quarters of 2006 (the period on which calendar 2006 cash basis revenues were based).
WTI Prices averaged 23.5% higher during that period than during the twelve months ended September
30, 2005. As a result, royalty revenues and cash distributions during 2006 rose approximately 21%
from 2005, even though revenues were adversely affected by the partial shutdown of the Prudhoe Bay
Unit in August 2006. The shutdown was primarily responsible for royalty revenues in the fourth
quarter of 2006 falling approximately 27% from average royalty revenues during the first three
quarters of the year. Chargeable Costs per barrel increased from $12.25 to $12.50, beginning in the
first quarter of 2006. The increase in Chargeable Costs, continued increases in the Cost Adjustment
Factor and increases in Production Taxes (which, during the quarter ended September 30, 2006,
reflected the new Alaska oil and gas production tax which became effective in August 2006) further
reduced the effect of increases in WTI Prices on the Trusts revenues in 2006.
|
|
|
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.
34
|
|
|
ITEM 8. |
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
BP PRUDHOE BAY ROYALTY TRUST
Index To Financial Statements
35
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 as of December 31, 2007 and 2006, 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, 2007. 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 assets, liabilities, and trust corpus of BP Prudhoe Bay Royalty Trust as of December
31, 2007 and 2006 and its distributable income and changes in trust corpus for each of the years in
the three-year period ended December 31, 2007 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, 2007, based on criteria established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our
report dated February 29, 2008 expressed an unqualified opinion on the effectiveness of the Trusts
internal control over financial reporting.
Dallas, Texas
February 29, 2008
36
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, |
|
|
|
2007 |
|
|
2006 |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty interest, net (Notes 1, 2 and 3) |
|
$ |
6,026 |
|
|
$ |
8,034 |
|
Cash and cash equivalents (Note 2) |
|
|
1,009 |
|
|
|
1,010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
7,035 |
|
|
$ |
9,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Trust Corpus |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued expenses |
|
$ |
443 |
|
|
$ |
191 |
|
|
|
|
|
|
|
|
|
|
Trust corpus (40,000,000 units of
beneficial interest authorized,
21,400,000 units issued and
outstanding) |
|
|
6,592 |
|
|
|
8,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and trust corpus |
|
$ |
7,035 |
|
|
$ |
9,044 |
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
37
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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty revenues |
|
$ |
177,318 |
|
|
$ |
184,864 |
|
|
$ |
152,978 |
|
Interest income |
|
|
81 |
|
|
|
75 |
|
|
|
37 |
|
Less: Trust administrative expenses |
|
|
(1,687 |
) |
|
|
(1,057 |
) |
|
|
(1,097 |
) |
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
$ |
175,712 |
|
|
$ |
183,882 |
|
|
$ |
151,918 |
|
|
|
|
|
|
|
|
|
|
|
Cash distributions |
|
$ |
175,713 |
|
|
$ |
183,883 |
|
|
$ |
151,908 |
|
|
|
|
|
|
|
|
|
|
|
Cash distributions per unit |
|
$ |
8.211 |
|
|
$ |
8.593 |
|
|
$ |
7.098 |
|
|
|
|
|
|
|
|
|
|
|
Units outstanding |
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
38
BP Prudhoe Bay Royalty Trust
Statements of Changes in Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust corpus at beginning of year |
|
$ |
8,853 |
|
|
$ |
10,876 |
|
|
$ |
12,881 |
|
Cash earnings |
|
|
175,712 |
|
|
|
183,882 |
|
|
|
151,918 |
|
Increase in accrued expenses |
|
|
(252 |
) |
|
|
(13 |
) |
|
|
(7 |
) |
Cash distributions |
|
|
(175,713 |
) |
|
|
(183,883 |
) |
|
|
(151,908 |
) |
Amortization of royalty interest |
|
|
(2,008 |
) |
|
|
(2,009 |
) |
|
|
(2,008 |
) |
|
|
|
|
|
|
|
|
|
|
Trust corpus at end of year |
|
$ |
6,592 |
|
|
$ |
8,853 |
|
|
$ |
10,876 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
39
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2007
(1) |
|
Formation of the Trust and Organization |
|
|
|
BP Prudhoe Bay Royalty Trust (the Trust), a grantor trust, was created as a Delaware statutory
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 BNYM (Delaware) (successor to 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 banking corporation, and BNYM (Delaware), a Delaware banking corporation. BNYM (Delaware) serves as
co-trustee in order to satisfy certain requirements of the Delaware Statutory 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. |
|
|
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 |
40
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2007
|
|
|
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, 2007, 2006 and 2005 was $0.38, $0.41 and $0.37, respectively. 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, 2007 and 2006, and the modified
cash earning and distributions and changes in Trust corpus for the years ended December 31,
2007, 2006 and 2005. 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, 2007 and 2006, 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 environment, financial markets and any other parameters used in determining these estimates
could cause actual results to differ, and the difference could be material.
41
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2007
The Royalty Interest is comprised of the following at December 31, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Royalty Interest (at inception) |
|
$ |
535,000 |
|
|
$ |
535,000 |
|
Less: Accumulated amortization |
|
|
(355,456 |
) |
|
|
(353,448 |
) |
Impairment write-down |
|
|
(173,518 |
) |
|
|
(173,518 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of period |
|
$ |
6,026 |
|
|
$ |
8,034 |
|
|
|
|
|
|
|
|
(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) |
|
Alaska Oil and Gas Production Tax |
|
|
|
The Alaska oil and gas production tax statutes were amended by a bill (the 2006 Tax) which
became effective on August 20, 2006. The 2006 Tax replaced an oil production tax levied at the
flat rate of 15% of the gross value at the point of production (the wellhead or field value)
of taxable oil produced from a producers leases or properties in the State of Alaska. Under the
2006 Tax, producers were taxed on the production tax value of taxable oil (gross value at the
point of production for the calendar year less the producers direct costs of exploring for,
developing, or producing oil or gas deposits located within the producers leases or properties
in Alaska for the year) at a rate equal to the sum of 22.5% plus a
progressivity rate determined by the average monthly production tax value of the oil produced.
The progressivity portion of the 2006 Tax was equal to 0.25% times the amount by which the
simple average for each calendar month of the daily production tax values per barrel of the oil
produced during the month exceeded $40 per barrel. |
|
|
|
On December 20, 2007, a bill (the 2007 Tax) took effect which further amended the Alaska oil
and gas production tax statutes in certain respects. The 2007 Tax changes the basic tax rate
from 22.5% to 25% and increases the progressivity rate. If the producers average monthly
production tax value per barrel is greater than $30 but not more than $92.50, the new
progressivity tax rate is 0.4% times the amount by which the average monthly production tax
value exceeds $30 per barrel. If the producers average monthly production tax value per barrel
is greater than $92.50, the progressivity tax rate is the sum of 25% and the product of 0.1% multiplied by the difference between the
average monthly production tax value per barrel and $92.50, except that the sum may not exceed
50%. |
42
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2007
|
|
The Trustee and BP Alaska entered into a letter agreement in October 2006 and an amendment
thereto in January 2008 (the Letter Agreement) to resolve issues associated with the 2006 Tax
and the 2007 Tax. The Letter Agreement modified the calculation of Production Taxes in the daily
Per Barrel Royalty calculation effective as of August 20, 2006, in the case of the 2006 Tax, and
effective December 20, 2007, in the case of the 2007 Tax. It also provides that the
retroactivity provisions of the respective tax bills are not applicable to the Per Barrel
Royalty calculation for periods prior to the effective dates of the 2006 Tax and the 2007 Tax. |
(6) |
|
Partial Shutdown of Prudhoe Bay Oil Field |
|
|
|
On August 7, 2006, BP announced that BP Alaska had commenced a shutdown of the Prudhoe Bay Field
as a result of the discovery of unexpectedly severe corrosion and a small spill from an oil
transit line in the Prudhoe Bay Field. BP subsequently determined to shut down only the Eastern
Operating Area of the field and continue production from the Western Operating Area. Clearance
from the U.S. Department of Transportation to restart production in the Eastern Operating Area
was received in September 2006. |
|
(7) |
|
Litigation Contingency |
|
|
|
In November 2006, a complaint was filed in the United States District Court for the District of
Alaska, purportedly as a class action on behalf of the public holders of units in the Trust,
against BP, the Trust, BP Alaska, Standard Oil and other unnamed defendants. In April 2007 the
plaintiff voluntarily dismissed the Trust as a defendant in the action and in September 2007,
the District Court dismissed all of the plaintiffs claims against BP, BP Alaska and Standard
Oil without prejudice. Other lawsuits are pending against BP, Standard Oil and BP Alaska in the
United States District Court for the Western District of Washington
and in the United States District Court for the Southern District of
New York. Although the
Trust is not a defendant in these cases, the Trust will incur legal and other expenses in
amounts which may be significant as a result of demands for production of documents made by the
plaintiffs on the Trustee and its agents and representatives. |
|
(8) |
|
Royalty Revenue Adjustments |
|
|
|
Certain of the royalty payments received by the Trust in 2007 were adjusted by BP Alaska to
compensate for underpayments or overpayments of the royalties due with respect to the quarters
ended prior to the dates of such payments. Average net production of crude oil and condensate
was less than 90,000 barrels per day during each of the third and fourth quarters of 2006 and
the second quarter of 2007. Royalty payments by BP Alaska with respect to those quarters were
based on estimates by BP Alaska of production levels because actual data was not available by
the dates on which payments were required to be made to the Trust. Subsequent recalculation by
BP Alaska of royalty payments due based on actual production data resulted in the payment
adjustments shown in the table below: |
43
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 Payments Received |
|
|
|
January |
|
|
April |
|
|
July |
|
|
October |
|
Royalty payment as
calculated |
|
$ |
41,470,000 |
|
|
$ |
39,297,000 |
|
|
$ |
44,164,111 |
|
|
$ |
49,636,093 |
|
Adjustment for
underpayment
(overpayment), plus
accrued interest |
|
|
1,736,000 |
|
|
|
(47,000 |
) |
|
|
|
|
|
|
1,061,954 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net payment received |
|
$ |
43,206,000 |
|
|
$ |
39,250,000 |
|
|
$ |
44,164,111 |
|
|
$ |
50,698,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9) |
|
Subsequent Event |
|
|
|
In January 2008, the Trust received a payment of $65,384,224 from BP Alaska. This payment
consisted of $65,284,449, representing the royalty payment due with respect to the Trusts
Royalty Interest for the quarter ended December 31, 2007, plus $63,775, representing the amount
of an underpayment by BP Alaska, including interest on the underpayment, of the royalty payment
due with respect to the quarter ended September 30, 2007. See Note 8 above. |
|
(10) |
|
Summary of Quarterly Results (Unaudited) |
|
|
|
A summary of selected quarterly financial information for the years ended December 31, 2007,
2006, and 2005 is as follows (in thousands, except unit data): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 Fiscal Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty revenues |
|
$ |
43,206 |
|
|
$ |
39,250 |
|
|
$ |
44,164 |
|
|
$ |
50,698 |
|
Interest income |
|
|
20 |
|
|
|
20 |
|
|
|
21 |
|
|
|
20 |
|
Trust administrative expenses |
|
|
(169 |
) |
|
|
(391 |
) |
|
|
(767 |
) |
|
|
(360 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
43,057 |
|
|
|
38,879 |
|
|
|
43,418 |
|
|
|
50,358 |
|
Cash distributions |
|
|
43,059 |
|
|
|
38,879 |
|
|
|
43,415 |
|
|
|
50,360 |
|
Cash distributions per unit |
|
|
2.0121 |
|
|
|
1.8168 |
|
|
|
2.0287 |
|
|
|
2.3533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 Fiscal Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty revenues |
|
$ |
45,383 |
|
|
$ |
47,539 |
|
|
$ |
55,797 |
|
|
$ |
36,145 |
|
Interest income |
|
|
14 |
|
|
|
18 |
|
|
|
22 |
|
|
|
21 |
|
Trust administrative expenses |
|
|
(157 |
) |
|
|
(296 |
) |
|
|
(279 |
) |
|
|
(325 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
45,240 |
|
|
|
47,261 |
|
|
|
55,540 |
|
|
|
35,841 |
|
Cash distributions |
|
|
45,246 |
|
|
|
47,258 |
|
|
|
55,538 |
|
|
|
35,841 |
|
Cash distributions per unit |
|
|
2.1143 |
|
|
|
2.2083 |
|
|
|
2.5952 |
|
|
|
1.6748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
44
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty revenues |
|
$ |
177,318 |
|
|
$ |
184,864 |
|
|
$ |
152,978 |
|
Interest income |
|
|
81 |
|
|
|
75 |
|
|
|
37 |
|
Trust administrative expenses |
|
|
(1,687 |
) |
|
|
(1,057 |
) |
|
|
(1,097 |
) |
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
175,712 |
|
|
|
183,882 |
|
|
|
151,918 |
|
Cash distributions |
|
|
175,713 |
|
|
|
183,883 |
|
|
|
151,908 |
|
Cash distributions per unit |
|
|
8.211 |
|
|
|
8.593 |
|
|
|
7.098 |
|
(11) |
|
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, 2007
($96.01 per barrel), December 31, 2006 ($61.06 per barrel) and December 31, 2005 ($61.04 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,
2007, 2006 and 2005, based on BP Alaskas latest reserve estimate at such time and the WTI
Prices on December 31, 2007, 2006 and 2005, were estimated to be 98, 81 and 85 million barrels,
respectively (of which 87, 69 and 73 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 |
45
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2007
|
|
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, 2007,
2006 and 2005, 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 $96.01, $61.06 and $61.04, respectively, were as follows (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
$ |
3,209,305 |
|
|
$ |
1,855,304 |
|
|
$ |
2,095,163 |
|
10% annual discount for
estimated timing of cash flows |
|
|
(1,609,463 |
) |
|
|
(803,320 |
) |
|
|
(885,424 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future
net cash flow (a) |
|
$ |
1,599,842 |
|
|
$ |
1,051,984 |
|
|
$ |
1,209,739 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The following are the principal sources of the change in the standardized measure of
discounted future net cash flows (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revision of previous quantity estimates |
|
$ |
64,461 |
|
|
$ |
(94,069 |
) |
|
$ |
2,472 |
|
Net changes in prices and production costs |
|
|
1,364,445 |
|
|
|
6,635 |
|
|
|
753,468 |
|
Net change in production taxes |
|
|
(778,644 |
) |
|
|
1,382 |
|
|
|
(116,558 |
) |
Other |
|
|
1,608 |
|
|
|
(1,073 |
) |
|
|
(370 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
651,870 |
|
|
|
(87,125 |
) |
|
|
639,012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income received (b) |
|
|
(209,172 |
) |
|
|
(191,604 |
) |
|
|
(173,224 |
) |
Accretion of discount |
|
|
105,195 |
|
|
|
120,974 |
|
|
|
67,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) during the year |
|
$ |
547,893 |
|
|
$ |
(157,755 |
) |
|
$ |
533,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) |
|
For the purpose of this calculation, royalty income received for 2007, 2006 and 2005
includes the following: |
|
|
|
|
|
Period October 1, 2007 through December 31, 2007 |
|
$ |
65,182 |
|
Period October 1, 2006 through December 31, 2006 |
|
$ |
43,206 |
|
Period October 1, 2005 through December 31, 2005 |
|
$ |
45,383 |
|
The above royalty income was received by the Trust in January 2008, 2007 and 2006, respectively.
46
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2007
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, 2005 |
|
|
85,313 |
|
Production |
|
|
(4,932 |
) |
Reserve estimate revisions |
|
|
697 |
|
Change caused by prices/costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated net proved reserves of oil and condensate at December 31, 2006 |
|
|
81,078 |
|
Production |
|
|
(5,249 |
) |
Reserve estimate revisions |
|
|
(10,792 |
) |
Change caused by prices/costs |
|
|
32,762 |
|
|
|
|
|
|
|
|
|
|
|
Estimated net proved reserves of oil and condensate at December 31, 2007 |
|
|
97,799 |
|
|
|
|
|
|
|
|
|
|
|
Proved reserves: |
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
85,313 |
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
81,078 |
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
97,799 |
|
|
|
|
|
|
47
|
|
|
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, 2007.
|
|
|
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 and the
assumptions utilized in arriving at the estimates contained in the report.
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 2007, 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 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.
48
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, 2007.
The Trustees assessment of the effectiveness of the Trusts internal control over financial
reporting as of December 31, 2007 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 internal control over financial reporting as of December 31, 2007,
based on criteria established in Internal Control Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). The Bank of New York, as 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, included in the accompanying Report of Management on Internal Control over Financial
Reporting. Our responsibility is to express 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, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
The 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. The
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 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
49
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, BP Prudhoe Bay Royalty Trust maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2007, based on criteria established in
Internal Control Integrated 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, 2007 and 2006, 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, 2007, and our report dated February 29, 2008 expressed an unqualified opinion on
those financial statements.
KPMG LLP
Dallas, Texas
February 29, 2008
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, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The Trust has no directors or executive officers. The Trust is administered by the Trustee
under the authority granted it in the Trust Agreement. The Trust Agreement grants the Trustee only
the rights and powers necessary to achieve the purposes of the Trust. See THE TRUST Duties and
Powers of Trustee in Item 1.
The Trustee may be removed with or without cause by vote of holders of a majority of the Units
at a meeting called and held as provided in the Trust Agreement. At the meeting the Unit holders
may appoint a successor trustee meeting the requirements set forth in the Trust Agreement. See THE
TRUST Resignation or Removal of Trustee in Item 1.
The Trust has not adopted a code of ethics. The standards of conduct governing the Trustee are
set forth in the Trust Agreement and Delaware law. Ethical standards applicable to the employees of
the Trustee are set forth in The Bank of New Yorks Code of Conduct which may be found at
www.bnymellon.com/ethics.
50
There is no audit committee or committee performing comparable functions responsible for
reviewing the audited financial statements of the Trust.
|
|
|
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 who receive no
compensation specifically related to their services to the Trust.
Under the Trust Agreement, the Trustee is entitled to receive on each Quarterly Record Date a
quarterly fee, currently consisting of: (i) a quarterly administrative fee of $.0017 per Unit
outstanding on the Quarterly Record Date plus $10.00 for each payment by wire transfer to a Unit
holder and (ii) a transfer service fee of $2.42 per Unit holder account as of the Quarterly Record
Date. Both the administrative service fee and the transfer service fee are subject to increase in
each calendar year by the proportionate increase, if any, during the preceding calendar year in the
Consumer Price Index (as defined in the Conveyance; see THE ROYALTY INTEREST Cost Adjustment
Factor in Item 1) during the preceding calendar year. The Trustee also bills the Trust for certain
reimbursable expenses. There is no compensation committee or committee performing similar functions
with authority to determine any compensation of the Trustee other than the fees and reimbursable
expenses provided for in the Trust Agreement.
The compensation received by the Trustee from the Trust during the three fiscal years ended
December 31, 2007 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfer Agent and Registrar |
Year ended December 31, |
|
Trustees Fees |
|
Fees |
|
|
|
|
|
|
|
|
|
2005 |
|
$ |
141,288 |
|
|
$ |
7,075 |
|
2006 |
|
|
147,081 |
|
|
|
6,860 |
|
2007 |
|
|
172,235 |
* |
|
|
6,494 |
|
|
|
|
* |
|
Includes $20,300 of extraordinary service fees. |
|
|
|
ITEM 12. |
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER
MATTERS |
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 February 28, 2008, 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 BNYM (Delaware), as co-trustee or in its
individual capacity.
51
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, AND DIRECTOR INDEPENDENCE |
There
has been no transaction by the Trust since the beginning of 2007, or any currently
proposed transaction in which a related person (as defined in Item 404 of Regulation S-K) had or
will have a direct or indirect material interest, except for payment to the Trustee of the fees and
reimbursement for expenses prescribed in the Trust Agreement. See Item 11 above.
The Trust has no independent directors. See Item 10 above.
|
|
|
ITEM 14. |
|
PRINCIPAL ACCOUNTANT FEES AND SERVICES |
Fees for services performed by KPMG LLP for the years ended December 31, 2007 and 2006 are:
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
Audit |
|
$ |
135,000 |
|
|
$ |
123,500 |
|
Audit related |
|
|
18,000 |
|
|
|
16,500 |
|
Tax |
|
|
200,000 |
|
|
|
200,000 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
353,000 |
|
|
$ |
340,000 |
|
|
|
|
|
|
|
|
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 AND 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, 2007 and 2006
Statements of Cash Earnings and Distributions for the years ended December 31, 2007,
2006 and 2005
Statements of Changes in Trust Corpus for the years ended December 31, 2007, 2006
and 2005
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.
52
(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, as amended May 8, 1989, among The British
Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard Oil Company and BP
Prudhoe Bay Royalty Trust. |
|
|
|
4.5
|
|
Letter agreement executed October 13, 2006 between BP Exploration (Alaska) Inc. and The Bank
of New York, as Trustee. |
|
|
|
4.6
|
|
Letter agreement executed January 11, 2008 between BP Exploration (Alaska) Inc. and The Bank
of New York, as Trustee. |
|
|
|
31
|
|
Rule 13a-14(a) certification. |
|
|
|
32
|
|
Section 1350 certification. |
53
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
BP PRUDHOE BAY ROYALTY TRUST
|
|
|
By: |
THE BANK OF NEW YORK, as Trustee
|
|
|
|
|
|
|
By: |
/s/ Remo Reale
|
|
|
|
Remo Reale |
|
|
|
Vice President |
|
|
March 11, 2008
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.
54
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. Incorporated by reference to the correspondingly numbered exhibit to the
Registrants Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (File No.
1-10243). |
|
|
|
4.2
|
|
Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc.
and The Standard Oil Company. Incorporated by reference to the correspondingly numbered
exhibit to the Registrants Annual Report on Form 10-K for the fiscal year ended December 31,
2006 (File No. 1-10243). |
|
|
|
4.3
|
|
Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay
Royalty Trust. Incorporated by reference to the correspondingly numbered exhibit to the
Registrants Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (File No.
1-10243). |
|
|
|
4.4
|
|
Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c.,
BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.
Incorporated by reference to the correspondingly numbered exhibit to the Registrants Annual
Report on Form 10-K for the fiscal year ended December 31, 2006 (File No. 1-10243). |
|
|
|
4.5
|
|
Letter agreement executed October 13, 2006 between BP Exploration (Alaska) Inc. and The Bank
of New York, as Trustee. Incorporated by reference to the correspondingly numbered exhibit to
the Registrants Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File
No. 1-10243). |
|
|
|
4.5
|
|
Letter agreement executed January 11, 2008 between BP Exploration (Alaska) Inc. and The Bank
of New York, as Trustee. Incorporated by reference to the correspondingly numbered exhibit to
the Registrants Current Report on Form 8-K dated January 11, 2008 (File No. 1-10243). |
|
|
|
31*
|
|
Rule 13a-14(a) certification. |
|
|
|
32*
|
|
Section 1350 certification. |