e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year ended December 31, 2009
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 1-10243
BP PRUDHOE BAY ROYALTY TRUST
(Exact name of registrant as specified in its charter)
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DELAWARE |
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(State or other jurisdiction
of incorporation or organization)
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13-6943724
(I.R.S. Employer Identification No.) |
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THE BANK OF NEW YORK MELLON, TRUSTEE
101 BARCLAY STREET
NEW YORK, NEW YORK
(Address of principal executive offices)
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10286
(Zip Code) |
Registrants telephone number, including area code: (212) 815-6908
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange on Which Registered |
UNITS OF BENEFICIAL INTEREST
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NEW YORK STOCK EXCHANGE |
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T (17 CFR § 232.405) during the preceding 12 months (or for such
shorter period that the registrant was required to submit and post such files). Yes o No
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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):
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Large Accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act Yes o No þ
The aggregate market value of Units held by nonaffiliates (computed by reference to the
closing sale price in New York Stock Exchange transactions on June 30, 2009 (the last business day
of the registrants most recently completed second fiscal quarter) was approximately
$1,476,600,000.
As of February 26, 2010, 21,400,000 Units of Beneficial Interest were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
TABLE OF CONTENTS
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EX-31 |
EX-32 |
EX-99 |
i
PART I
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 Mellon (formerly named The Bank of New York), as trustee (the Trustee), and F. James
Hutchinson, co-trustee (BNY Mellon Trust of Delaware, formerly named The Bank of New York
(Delaware), successor co-trustee). BP Alaska and Standard Oil are wholly owned subsidiaries of
BP p.l.c. (BP). The Trustees corporate trust offices are located at 101 Barclay Street, New
York, New York 10286 and its telephone number is (212) 815-6908.
The Trust electronically files annual reports on Form 10-K, quarterly reports on Form 10-Q
and, when certain events require them, current reports on Form 8-K with the Securities and Exchange
Commission (SEC). The public may read and copy any materials filed by the Trust with the SEC at
the SECs Public Reference Room at 100 F Street, N.E., 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 website is http://www.sec.gov.
The Trust does not maintain an Internet website, but certain information concerning the Trust
and the Trust Units may be obtained from the BusinessWire website at the following page location:
http://www.businesswire.com/portal/site/home/news/company?vnsId=41701. 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 Mellon, 101 Barclay Street, Floor 8W, New York, NY 10286, Attention: Mr. Geovanni
Barris, Corporate Trust Department; by telephone to: (212) 815-6908; or by e-mail to:
geovanni.barris@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
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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 in this report 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. BNY Mellon Trust of 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 Mellon 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.
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* The term barrel is a unit of measure of
petroleum liquids equal to 42 United States gallons corrected to 60 degrees
Fahrenheit temperature. |
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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 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.
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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 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
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investment banking firm, commercial banking firm or other entity qualified to give an opinion
as to the fair market value of the assets of the Trust, or (ii) the number of outstanding Units
multiplied by (a) the closing price of Units on the day of termination of the Trust on the stock
exchange on which the Units are listed, or (b) if the Units are not listed on any stock exchange
but are traded in the over-the-counter market, the closing bid price on the day of termination of
the Trust as quoted on the NASDAQ Stock Market. 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
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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 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 1989
Working Interests), or (ii) the actual average daily net production of crude oil and condensate
for the quarter from the 1989 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 1989
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
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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.
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 $12.25 during 2005, $12.50 during 2006, $12.75 during
2007, $13.00 during 2008 and $13.25 during 2009. Chargeable Costs for 2010 and subsequent years are
shown in the following table:
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Calendar |
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Chargeable Costs |
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Chargeable Costs |
year |
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per barrel |
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year |
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per barrel |
2010 |
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$ |
14.50 |
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2016 |
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$ |
17.10 |
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2011 |
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16.60 |
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2017 |
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17.20 |
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2012 |
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16.70 |
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2018 |
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20.00 |
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2013 |
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16.80 |
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2019 |
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23.75 |
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2014 |
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16.90 |
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2020 |
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26.50 |
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2015 |
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17.00 |
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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 deductible with respect to the Royalty Production
under the Alaska oil and gas production tax statutes, AS 43.55.10 et seq. (the Production Tax
Statutes) 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
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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.
In August 2006 Alaska adopted amendments to the Production Tax Statutes (Chapter 2, Third
Special Session Laws of Alaska 2006) (the 2006 Amendments) which replaced the Old Tax. Commencing
with the 2006 Amendments, 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 Amendments 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 Amendments increased the
surcharge on oil produced from leases or properties in Alaska from $0.03 to $0.04 per barrel.
In December 2007, a bill (Chapter 1, Second Special Session Laws of Alaska 2007) (popularly
titled Alaskas Clear and Equitable Share or ACES) took effect and further amended the
Production Tax Statutes in certain respects. ACES changed the basic tax rate from 22.5% to 25% and
increased 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 Amendments, 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 ACES 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 ACES, 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.
ACES authorizes the Alaska Department of Revenue (DOR) to interpret and apply the amendments
to the Production Tax Statutes. DOR is allowed 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 regulations provide, it may wish to amend the Consensus Principles. Any such amendment would require the consent of the Trustee. If any such
amendment should be proposed, the Trustee will evaluate
10
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.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average WTI |
|
|
|
|
|
Cost Adjustment |
|
Adjusted Chargeable |
|
|
|
|
|
Average Per Barrel |
|
|
Price |
|
Chargeable Costs |
|
Factor |
|
Costs |
|
Production Taxes(1) |
|
Royalty |
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Qtr 2007 |
|
|
90.93 |
|
|
|
12.75 |
|
|
|
1.618 |
|
|
|
20.63 |
|
|
|
22.29 |
|
|
|
48.01 |
|
1st Qtr 2008 |
|
|
97.78 |
|
|
|
13.00 |
|
|
|
1.630 |
|
|
|
21.19 |
|
|
|
33.58 |
|
|
|
43.01 |
|
2nd Qtr 2008 |
|
|
124.34 |
|
|
|
13.00 |
|
|
|
1.668 |
|
|
|
21.68 |
|
|
|
52.37 |
|
|
|
50.29 |
|
3rd Qtr 2008 |
|
|
118.69 |
|
|
|
13.00 |
|
|
|
1.687 |
|
|
|
21.93 |
|
|
|
48.18 |
|
|
|
48.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Qtr 2008 |
|
|
58.03 |
|
|
|
13.00 |
|
|
|
1.636 |
|
|
|
21.26 |
|
|
|
11.42 |
|
|
|
25.35 |
|
1st Qtr 2009 |
|
|
43.20 |
|
|
|
13.25 |
|
|
|
1.634 |
|
|
|
21.65 |
|
|
|
5.43 |
|
|
|
16.13 |
|
2nd Qtr 2009 |
|
|
59.74 |
|
|
|
13.25 |
|
|
|
1.647 |
|
|
|
21.82 |
|
|
|
11.03 |
|
|
|
26.89 |
|
3rd Qtr 2009 |
|
|
68.13 |
|
|
|
13.25 |
|
|
|
1.662 |
|
|
|
22.02 |
|
|
|
14.57 |
|
|
|
31.54 |
|
|
|
|
(1) |
|
Production Taxes for the third quarter of 2006 through the fourth quarter of 2007 reflect the
effect of the 2006 Amendments of the Production Tax Statutes. Production Taxes for the first
quarter of 2008 and subsequent periods reflect the application of ACES. |
11
|
|
|
(2) |
|
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
payment 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 Mellon). 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 Mellon).
Reports to Unit Holders
After the end of each calendar year, the Trustee mails a report to the persons who held Units
of record during the year containing information to enable them to make the calculations necessary
for federal and Alaska income tax purposes, including the calculation of any depletion or other
deduction which may be available to them for the calendar year. In addition, after the end of each
calendar year the Trustee mails Unit holders an annual report containing a copy of this Form 10-K
and certain other information required by the Trust Agreement.
Limited Liability of Unit Holders
The Trust Agreement provides that the Unit holders are, to the full extent permitted by
Delaware law, entitled to the same limitation of personal liability extended to stockholders of
private corporations for profit under Delaware law.
12
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.
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
13
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 1989 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, 2009 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 Alaskas participation in oil rim ownership do not affect calculation of Royalty
Production from the 1989 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 1989 Working Interests and have not increased the Trusts Royalty Interest. |
14
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 1989 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 1989 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, 2009, approximately 11.2 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.
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.
15
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, 2009 there were about 1,037 active
producing oil wells, 32 gas reinjection wells, 216 water injection wells and 33 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 293
barrels per day in 2005, 223 barrels per day in 2006*, 232 barrels per day in 2007, 232
barrels per day in 2008 and 243 barrels per day in 2009.
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 1989 Working Interests have
been as follows during the past five years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Condensate |
|
Calendar |
|
|
|
|
|
Net to 1989 Working |
|
|
|
|
|
|
Net to 1989 Working |
|
year |
|
Total field |
|
|
Interests |
|
|
Total field |
|
|
Interests |
|
|
|
|
|
|
|
(thousand barrels per day) |
|
|
|
|
|
2005 |
|
|
228.9 |
|
|
|
101.5 |
|
|
|
96.4 |
|
|
|
11.7 |
|
2006 |
|
|
173.9 |
|
|
|
77.1 |
|
|
|
76.7 |
|
|
|
9.3 |
|
2007 (a) |
|
|
184.1 |
|
|
|
81.6 |
|
|
|
77.9 |
|
|
|
9.4 |
|
2008 |
|
|
192.7 |
|
|
|
85.4 |
|
|
|
69.4 |
|
|
|
8.4 |
|
2009 |
|
|
189.1 |
|
|
|
83.9 |
|
|
|
63.0 |
|
|
|
7.6 |
|
|
|
|
(a) |
|
2007 production figures reported in the Trusts Annual Report on Form 10-K for
the year ended December 31, 2007 have been revised to reflect actual production for the
year. |
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
|
|
|
* |
|
The August 2006 partial shutdown of the
Prudhoe Bay Unit caused a temporary impact on production from the east side of
the Unit. |
16
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 (1,288 km) to the south,
where it is either loaded onto marine tankers or stored temporarily. It currently takes the oil
about 13 days to make the trip from the Prudhoe Bay Unit to Valdez, due to declining flows of oil
from the North Slope. TAPS has a maximum daily average throughput of approximately 1.14 million
barrels of oil; recently, however, the pipeline has been moving approximately 700,000 barrels 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. In December 2008, BP completed the
replacement of approximately 16 miles of oil transit lines. BP Alaska has implemented new integrity
management and corrosion monitoring practices that supplement or replace the practices that existed
in 2006. BP Alaskas integrity management practices meet the requirements of 49 CFR 195.452 for
pipeline integrity management in high consequence areas.
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.
Reserve Estimates
Proved oil reserves attributable to the 1989 Working Interests at December 31, 2009 are those
quantities of oil which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible from 2009 forward from known reservoirs and
under existing
|
|
|
* |
|
An electronic device including magnetic flux
leakage and ultrasonic thickness testing systems that is propelled through a
pipeline to inspect the pipeline wall. |
17
economic conditions, operating methods and government regulations. 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. 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.
There is no precise method of forecasting the allocation of reserve volumes to 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 1989 Working Interests. The reserve volumes attributable to the 1989
Working Interests are estimated using an allocation of reserve volumes based on estimated future
production and the average 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.
The reserves attributable to the 1989 Working Interests constitute only a part of the overall
reserves in the Prudhoe Bay Unit. BP Alaska has estimated that the net remaining proved reserves
allocated to the Trust as of December 31, 2009 were 68.144 million barrels of oil and condensate,
of which 57.077 million barrels are proved developed reserves* and 11.067 million
barrels are proved undeveloped reserves+. To the extent that the estimated volumes of
proved undeveloped reserves include reserves the development of which is scheduled to commence
after five years, the inclusions are based on a development plan which calls for drilling wells
over an extended period of time given the magnitude of the development. BP has a historical record
of completing comparable projects. Approximately 10.8 million barrels (net) of proved undeveloped
reserves allocated to the Trust were converted into proved developed reserves during 2009. Based on
the 2009 twelve-month average WTI Price of $61.18 per barrel, other economic parameters
prescribed by the Conveyance, and utilizing procedures specified in Financial Accounting Standards
Board Accounting Standards Codification (FASB ASC) 932, Extractive Activities Oil and Gas, BP
Alaska calculated that as of December 31, 2009 production of oil and condensate from the proved
reserves allocated to the 1989 Working Interests will result in estimated future net revenues to
the Trust of $1,331 million, with a present value of $836.6 million. BPAlaska has advised the
Trustee that Mike Smith, BPs Segment Reserves Authority, is the petroleum engineer primarily
responsible for overseeing the preparation of the reserve estimate. He has over 35 years of
diversified industry experience with the past ten years spent as the head of the reservoir
management
|
|
|
* |
|
Proved developed reserves are reserves that
can be expected to be recovered through existing wells with existing equipment
and operating methods or in which the cost of the required equipment is
relatively minor compared to the cost of a new well. |
|
+ |
|
Proved undeveloped reserves are reserves that
are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for
recompletion. |
|
|
|
The unweighted arithmetic average of the WTI
Price on the first day of each month during the year. |
18
function within BP. He is a member of the Society of Petroleum Engineers and the Institute of
Materials, Minerals and Mining.
BP Alaskas estimates of the proved reserves allocated to the Trust, estimated future net
revenues to the Trust, and the remaining period of economic production from the Prudhoe Bay field
have been reviewed by Miller and Lents, Ltd., an international oil and gas consulting firm, as set
forth in their report which is filed as Exhibit 99 to this report
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, and the natural production declines discussed above under Historical Production, BP
Alaskas net production of oil and condensate allocated to the Trust from proved reserves was less
than 90,000 barrels per day on an annual basis in 2008 and 2009. BP Alaska anticipates that its
average net production of oil and condensate allocated to the Trust from proved reserves will be
below 90,000 barrels per day on an annual average basis most 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 2009 twelve-month average WTI Price
of $61.18 per barrel, 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 2023. BP Alaska expects continued economic production from the Prudhoe Bay field
at a declining rate through 2060; however, for the economic conditions and production forecast as
of December 31, 2009 the Per Barrel Royalty will be zero following the year 2023.
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.
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
19
on BP Alaskas current method of operations, the effect of future legislation and regulations
cannot be predicted.
Since the end of 2006, the corrosion monitoring and mitigation practices for the oil transit
lines in the Prudhoe Bay Unit have been monitored and reviewed by the U.S. Department of
Transportation. The construction, testing, and commissioning of the new replacement oil transit
lines have been inspected by DOT inspectors. The replacement lines have been constructed and are
operated and maintained in accordance with the requirements of the Pipeline Inspection, Protection,
Enforcement and Safety Act of 2006 even though the applicable requirements of the subsequent
regulations are not phased in until 2012. 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.
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.
20
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 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
21
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.
Widely Held Fixed Investment Trusts
The Trustee assumes that some Trust Units are held by a middleman, as such term is broadly
defined in the U.S. Treasury Regulations (which includes custodians, nominees, certain joint
owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee
considers the Trust to be a widely held fixed investment trust (WHFIT) for U.S. Federal income
tax purposes. The Bank of New York Mellon is the representative of the Trust that will provide tax
information in accordance with applicable U.S. Treasury Regulations governing the information
reporting requirements of the Trust as a WHFIT. For information contact The Bank of New York
Mellon, Corporate Trust Trustee Administration, 101 Barclay Street, New York, NY 10286, telephone
number (212) 815-6908.
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.
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.
22
|
|
|
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 been declining during recent years and the decline is expected to continue. Royalty payments to
the Trust are projected to cease after 2023. Production estimates included in this report are based
on economic conditions and production forecasts as of the end of 2009, 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 1989 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 could accelerate
the decline in Royalty Production from the Prudhoe Bay field. |
Two competing plans for construction of a natural gas pipeline to bring natural gas from the
North Slope to the U.S. market have been launched and have reached the project development stage.
Two subsidiaries of Calgary-based TransCanada Corporation (TransCanada) have been issued a
license by the state of Alaska under the Alaska Gasline Inducement Act (AGIA) to construct a
large-diameter natural gas pipeline from the North Slope. Under the license, the state will provide
up to $500 million in matching funds and other incentives in exchange for TransCanada doing its
best to secure customers for the pipeline, financing, and regulatory clearances from the Federal
Energy Regulatory Commission (FERC) and Canadian authorities. TransCanada and affiliates of
ExxonMobil have combined to promote a joint venture named the Alaska Pipeline Project.
Separately, BP and ConocoPhillips have combined resources in a joint venture called Denali
The Alaska Gas Pipeline, LLC (Denali) without support for the project from Alaska under the AGIA.
The Alaska Pipeline Project and Denali both contemplate a large-diameter pipeline extending
from the North Slope through Alaska, and then into Canada through the Yukon Territory and British
Columbia to the existing Alberta Storage Hub. The Alaska Pipeline Project proposal also includes an
alternative pipeline route that would extend from the North Slope to a third-party liquefied
natural gas terminal near Valdez, Alaska.
The Alaska Pipeline Project has issued a notice of a 90-day Open Season, beginning on April
30, 2010, to be conducted in accordance with FERC regulations. Denali plans to file a plan with
FERC in April 2010 to conduct an Open Season beginning in July 2010. During their respective Open
Seasons the two competing consortia will seek customers to make long-term firm transportation
commitments to their respective projects. There is no assurance that either project will move from
the development stage to licensing and construction of a pipeline. If either project is successful,
gas could commence flowing from the North Slope to market in the lower 48 states within eight to
ten years.
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,
23
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 1989 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 1989 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
changes to the Alaska Production Tax Statutes. |
The 2007 adoption of ACES (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 to the extent
that it has caused BP Alaska and the other owners of working
interests in the Prudhoe Bay Unit to
reduce or defer investment in oil production infrastructure renewal, well development and
implementation of new technology. ACES, in addition to increasing the basic oil production tax rate
and the progressivity factor, also eliminates or reduces many deductions and credits permitted
under the 2006 Amendments. BP Alaskas capital spending in Alaska during 2010 is expected to be
approximately $850 million, down 15% from more than $1 billion during 2009.
|
|
|
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 1989 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. These fluctuations were especially pronounced during
2008 and 2009. 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 including, most recently, the global economic
recession. Future domestic and international events and conditions may produce wide swings in crude
oil prices over relatively short periods of time.
It is increasingly likely that the Trusts revenues in future periods also will be affected by
decreases in production from the 1989 Working Interests. BP Alaskas average net production of oil
and condensate allocated to the Trust from proved reserves was less than 90,000 barrels per day on
an annual basis during 2008 and 2009, and the Trustee has been advised that BP Alaska expects that
average net production allocated to the Trust from the proved reserves will be less than 90,000
barrels a day on an annual basis in 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
24
three-mile segment of transit line on the western side of the Prudhoe Bay Unit following
discovery of a large oil spill.
BP Alaska completely replaced approximately 16 miles of transit lines on the eastern and
western sides of the Prudhoe Bay Unit 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.
|
|
|
Oil production from the Prudhoe Bay Unit could be interrupted by damage to the
Trans-Alaska Pipeline System from natural causes, accidents, deliberate attacks or
declining oil flows. |
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. Recently, the pipeline
has become susceptible to damage resulting from declining flows of oil from the North Slope. Slower
flows cause the temperature of the oil in the pipeline to cool faster, increasing the rate of
deposit of wax, which coats pipe walls, hides corrosion and clogs sensors on smart pigs sent
through the pipeline to detect it. Even lower flow rates projected in the future may lead to
internal damage caused by ice formation within the pipe and external damage from frost heaves under
buried segments. Major upgrades to the pipeline may be required to counteract the effects of cooler
oil temperature. 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 1989 Working Interests may be interrupted or discontinued by BP
Alaska. |
BP Alaska has no obligation to continue production from the 1989 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 1989 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 in the
Conveyance. The WTI Price does not necessarily correspond to the actual price realized by BP Alaska
for crude oil produced from the 1989 Working Interests, and Chargeable Costs and Production Taxes
may not bear any relation
25
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 1989 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 Securities Exchange Act of 1934 (the
Exchange Act) that remain unresolved.
Reference is made to Item 1 for the information required by this item.
|
|
|
ITEM 3. |
|
LEGAL PROCEEDINGS |
None
|
|
|
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, 2009.
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,
2009.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions |
|
|
|
High |
|
|
Low |
|
|
Per Unit |
|
2008: |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
97.13 |
|
|
$ |
71.01 |
|
|
$ |
3.046 |
|
Second Quarter |
|
|
103.49 |
|
|
|
88.51 |
|
|
|
2.670 |
|
Third Quarter |
|
|
108.40 |
|
|
|
77.64 |
|
|
|
3.053 |
|
Fourth Quarter |
|
|
95.47 |
|
|
|
58.08 |
|
|
|
2.937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
83.07 |
|
|
|
50.04 |
|
|
|
1.637 |
|
Second Quarter |
|
|
75.27 |
|
|
|
64.26 |
|
|
|
0.992 |
|
Third Quarter |
|
|
76.37 |
|
|
|
63.25 |
|
|
|
1.650 |
|
Fourth Quarter |
|
|
83.40 |
|
|
|
71.50 |
|
|
|
1.730 |
|
26
As of February 23, 2010, 21,400,000 Units were outstanding and were held by 577 holders of
record. No Units were purchased by the Trust or any affiliated purchaser during the year ended
December 31, 2009.
Future payments of cash distributions are dependent on such factors as prevailing WTI Prices,
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 1989 Working Interests. See THE ROYALTY INTEREST in Item 1.
|
|
|
ITEM 6. |
|
SELECTED FINANCIAL DATA |
The following table presents in summary form selected financial information regarding the
Trust.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands, except per Unit amounts) |
|
Royalty revenues |
|
$ |
130,014 |
|
|
|
252,298 |
|
|
|
177,318 |
|
|
|
184,864 |
|
|
|
152,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement revenue |
|
$ |
29,474 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
$ |
4 |
|
|
|
33 |
|
|
|
81 |
|
|
|
75 |
|
|
|
37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust administration expenses |
|
$ |
1,459 |
|
|
|
1,797 |
|
|
|
1,687 |
|
|
|
1,057 |
|
|
|
1,097 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
$ |
158,033 |
|
|
|
250,534 |
|
|
|
175,712 |
|
|
|
183,882 |
|
|
|
151,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions |
|
$ |
128,575 |
|
|
|
250,525 |
|
|
|
175,713 |
|
|
|
183,883 |
|
|
|
151,908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions per unit |
|
$ |
6.008 |
|
|
|
11.707 |
|
|
|
8.211 |
|
|
|
8.593 |
|
|
|
7.098 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(dollar amounts in thousands) |
|
Trust corpus |
|
$ |
32,273 |
|
|
|
4,757 |
|
|
|
6,592 |
|
|
|
8,853 |
|
|
|
10,876 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
32,484 |
|
|
|
5,035 |
|
|
|
7,035 |
|
|
|
9,044 |
|
|
|
11,054 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
27
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.
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 1989
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 likely that the Trusts revenues in future periods also will be affected by increases and
decreases in production from the 1989 Working Interests. BP Alaskas net production of oil and
condensate allocated to the Trust from proved reserves was less than 90,000 barrels per day on an
annual basis during 2008 and 2009. The Trustee has been advised that BP Alaska expects that average
net production allocated to the Trust from the proved reserves will be less than 90,000 barrels a
day on an annual basis in future years.
BP Alaska estimates Royalty Production from the 1989 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 1989 Working Interests is below 90,000 barrels per day,
calculation by BP Alaska of
28
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 2008 and 2009 and the period of 2010 up to the date of this report, WTI
Prices have been above the level necessary for the Trust to receive a Per Barrel Royalty. Whether
the Trust will be entitled to future distributions during the remainder of 2010 will depend on WTI
Prices prevailing during the remainder of the year.
In June 2009, the Financial Accounting Standards Board (FASB) issued a new accounting
standard, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles. This new accounting standard established the FASB Accounting Standards
Codification, or FASB ASC, as the source of authoritative generally accepted accounting principles
(GAAP) recognized by the FASB for non-governmental entities. All existing accounting standards
have been superseded and accounting literature not included in the FASB ASC is considered
non-authoritative. Adoption of the FASB ASC did not effect significant changes in GAAP and had no
effect on the reporting of Trusts financial condition or results of operations.
2009 compared to 2008
WTI Prices fell precipitously during the fourth quarter of 2008, from an average of
approximately $104 per barrel during September 2008 to an average of approximately $41 per barrel
during December 2008. WTI Prices then rose gradually during the first three quarters of 2009,
reaching a high average monthly price of approximately $71 during August 2009. Average WTI Prices
for the twelve months ended September 30, 2009 were 47% lower than during the preceding
twelve-month period, which resulted in royalty revenues that were 49% lower during the twelve
months ended December 31, 2009 than during the twelve months ended December 31, 2008. Cash earnings
during 2009 declined only 37% from 2008, however, as a result of the receipt by the Trust during
December 2009 of a $29,474,000 payment from BP Alaska in settlement of certain claims that arose
from the 2006 partial shutdown of the Prudhoe Bay Unit. Production Taxes charged against the Per
Barrel Royalty during the twelve months ended September 30, 2009 declined approximately 73% from
the preceding twelve-month period as a result of the progressivity feature of the 2007 ACES
amendments to the Alaska oil and gas tax statutes (see THE ROYALTY INTEREST Production Taxes
in Item 1). Trust administrative expenses declined approximately 19% during the year ended December
31, 2009, principally due to declining legal fees and expenses.
2008 compared to 2007
WTI Prices rose rapidly during the fourth quarter of 2007 and throughout the first half of
2008, reaching a high of over $145 per barrel early in July 2008 before receding to an average of
approximately $104 per barrel during September 2008. As a result of the increases in WTI Prices,
average WTI Prices for the twelve months ended September 30, 2008 were 67% higher than during the
preceding twelve-month period. Royalty revenues and cash earnings rose 42% and 43%, respectively,
during the twelve months ended December 31, 2008 compared to the twelve months ended December 31,
2007, but the
29
higher tax rates imposed by ACES, imposed a significant burden on Per Barrel Royalties.
Production taxes charged against the average Per Barrel Royalty were approximately 264% higher with
respect to the twelve months ended September 30, 2008 than during the twelve months ended September
30, 2007. Trust administrative expenses for 2008 rose 6.5% from 2007, principally due to legal fees
and expenses related litigation and other issues arising from the 2006 shutdown of the Prudhoe Bay
field.
|
|
|
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.
30
|
|
|
ITEM 8. |
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
BP PRUDHOE BAY ROYALTY TRUST
Index To Financial Statements
31
Report of Independent Registered Public Accounting Firm
Trustee and Holders of Trust Units of
BP Prudhoe Bay Royalty Trust:
We have audited the accompanying statements of assets, liabilities, and trust corpus of BP Prudhoe
Bay Royalty Trust (the Trust) as of December 31, 2009 and 2008, 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, 2009. These financial statements are the responsibility of The Bank of
New York Mellon (formerly named 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, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in note 2 to the financial statements, these financial statements 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 the Trust as of December 31, 2009 and 2008
and its cash earnings and distributions and changes in trust corpus for each of the years in the
three year period ended December 31, 2009 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 Trusts internal control over financial reporting as of December 31,
2009, 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 March
1, 2010 expressed an unqualified opinion on the effectiveness of the Trusts internal control over
financial reporting.
KPMG LLP
Dallas, Texas
March 1, 2010
32
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, |
|
|
|
2009 |
|
|
2008 |
|
Assets |
|
|
|
|
|
|
|
|
Royalty interest, net (Notes 1, 2 and 3) |
|
$ |
2,009 |
|
|
$ |
4,017 |
|
Cash and cash equivalents (Note 2) |
|
|
30,475 |
|
|
|
1,018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
32,484 |
|
|
$ |
5,035 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Trust Corpus |
|
|
|
|
|
|
|
|
Accrued expenses |
|
$ |
211 |
|
|
$ |
278 |
|
|
|
|
|
|
|
|
|
|
Trust corpus (40,000,000 units of
beneficial interest authorized,
21,400,000 units issued and
outstanding) |
|
|
32,273 |
|
|
|
4,757 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and trust corpus |
|
$ |
32,484 |
|
|
$ |
5,035 |
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
33
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, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Royalty revenues |
|
$ |
130,014 |
|
|
$ |
252,298 |
|
|
$ |
177,318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement revenue (Note 7) |
|
|
29,474 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
4 |
|
|
|
33 |
|
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Trust administrative expenses |
|
|
(1,459 |
) |
|
|
(1,797 |
) |
|
|
(1,687 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
$ |
158,033 |
|
|
$ |
250,534 |
|
|
$ |
175,712 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions |
|
$ |
128,575 |
|
|
$ |
250,525 |
|
|
$ |
175,713 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions per unit |
|
$ |
6.008 |
|
|
$ |
11.707 |
|
|
$ |
8.211 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units outstanding |
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
21,400,000 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
34
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, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Trust corpus at beginning of year |
|
$ |
4,757 |
|
|
$ |
6,592 |
|
|
$ |
8,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
158,033 |
|
|
|
250,534 |
|
|
|
175,712 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in accrued expenses |
|
|
67 |
|
|
|
165 |
|
|
|
(252 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions |
|
|
(128,575 |
) |
|
|
(250,525 |
) |
|
|
(175,713 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of royalty interest |
|
|
(2,009 |
) |
|
|
(2,009 |
) |
|
|
(2,008 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust corpus at end of year |
|
$ |
32,273 |
|
|
$ |
4,757 |
|
|
$ |
6,592 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
35
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
(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 Mellon (the
Trustee) and BNY Mellon Trust of Delaware (successor to The Bank of New York (Delaware)), as
co-trustee. Standard Oil and BP Alaska are indirect wholly owned subsidiaries of 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, 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. 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 Mellon, a New York banking corporation, and
BNY Mellon Trust of Delaware, a Delaware banking corporation. BNY Mellon Trust of Delaware
serves as co-trustee in order to satisfy certain requirements of the Delaware Statutory Trust
Act. The Bank of New York Mellon 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 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. |
36
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
|
b. |
|
After December 31, 2010: (i) upon a vote of Trust unit holders of not less than 60% of
the outstanding Trust units, or (ii) at such time the net revenues from the Royalty
Interest for two
successive years commencing after 2010 are less than $1,000,000 per year (unless the net
revenues during such period are materially and adversely affected by certain events). |
|
|
In order to ensure the Trust has the ability to pay future expenses, the Trust established a
cash reserve account which the Trustee believes is sufficient to pay approximately one years
current and expected liabilities and expenses of the Trust. |
(2) |
|
Basis of Accounting |
|
|
|
The financial statements of the Trust are prepared on a modified cash basis and reflect the
Trusts assets, liabilities, corpus, earnings, and distributions, as follows: |
|
a. |
|
Revenues are recorded when received (generally within 15 days of the end of the
preceding quarter) and distributions to Trust unit holders are recorded when paid. |
|
|
b. |
|
Trust expenses (which include accounting, engineering, legal, and other professional
fees, trustees fees, and out-of-pocket expenses) are recorded on an accrual basis. |
|
|
c. |
|
Cash reserves may be established by the Trustee for certain contingencies that would
not be recorded under generally accepted accounting principles. |
|
|
d. |
|
Amortization of the Royalty Interest is calculated based on the units of production
method. Such amortization is charged directly to the Trust corpus, and does not affect cash
earnings. The daily rate for amortization per net equivalent barrel of oil for the years
ended December 31, 2009, 2008 and 2007 was $0.38, $0.38 and $0.38, 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 the
Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) 360,
Property, Plant, and Equipment. 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, 2009 and 2008, and the modified
cash earning and distributions and changes in Trust corpus for the years ended December 31,
2009, 2008 and 2007. 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, 2009 and 2008, cash equivalents which represent the cash reserve consist of
U.S. treasury bills with an initial term of less than three months. |
37
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
|
|
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. |
(3) |
|
Royalty Interest |
|
|
|
The Royalty Interest is comprised of the following at December 31, 2009 and 2008 (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Royalty Interest (at inception) |
|
$ |
535,000 |
|
|
$ |
535,000 |
|
Less:Accumulated amortization |
|
|
(359,473 |
) |
|
|
(357,465 |
) |
Impairment write-down |
|
|
(173,518 |
) |
|
|
(173,518 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of period |
|
$ |
2,009 |
|
|
$ |
4,017 |
|
|
|
|
|
|
|
|
(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 Amendments)
which became effective in August 2006. The 2006 Amendments 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 Amendments, 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 rate imposed by the 2006 Amendments 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 December 2007, a bill (popularly titled Alaskas Fair and Equitable Share or ACES) took
effect which further amended the Alaska oil and gas production tax statutes in certain respects.
|
38
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
|
|
ACES changed the basic tax rate from 22.5% to 25% and increased the progressivity rate. If the
producers average monthly production tax value per barrel is greater than $30 but not more than
$92.50, the 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%. |
|
|
|
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
Amendments and ACES. 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 Amendments, and effective December 20, 2007, in the case of ACES. 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 Amendments and
ACES. |
(6) |
|
Legal Expenses |
|
|
|
The Trust incurred legal and other expenses as a result of litigation and other issues arising
out of the August 2006 shutdown of the Prudhoe Bay field. Legal fees and expenses contributed
materially to the Trust administrative expenses during 2007, 2008 and 2009. |
(7) |
|
Settlement Payment |
|
|
|
In 2009, the Trust entered into a settlement agreement with BP Alaska to resolve certain issues
related to the temporary shutdown of the Prudhoe Bay field following oil spills on March 2, 2006
and August 6, 2006 and to compromise any claims that the Trust and past, present, and future
holders of Trust units may have relating to conduct by BP Alaska that may have resulted in a
reduction of the royalty payments received by the Trust in 2006, 2007 and 2008. Under the
settlement agreement, BP Alaska paid $29,469,081 into an interest-bearing escrow account, to be
released by the escrow agent and paid to the Trust upon final approval by the Delaware Chancery
Court of the settlement agreement, and the dismissal of certain litigation brought in the United
States District Court for the Southern District of New York against BP Alaska and other parties
having become final. |
|
|
|
The settlement amount and accrued interest, totaling $29,474,410, was released from escrow and
paid to the Trust on December 24, 2009. See Note 9 below. |
(8) |
|
Royalty Revenue Adjustments |
|
|
Certain of the royalty payments received by the Trust in 2009, 2008 and 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 from the proved reserves allocated to the Trust was less than 90,000 barrels per day
during certain quarters. 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 (in thousands): |
39
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Payments Received |
|
|
|
January |
|
|
April |
|
|
July |
|
|
October |
|
Royalty
payment as
calculated |
|
$ |
34,481 |
|
|
$ |
21,449 |
|
|
$ |
36,051 |
|
|
$ |
37,621 |
|
Adjustment for
underpayment
(overpayment), plus
accrued interest |
|
|
799 |
|
|
|
|
|
|
|
|
|
|
|
(387 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net payment received |
|
$ |
35,280 |
|
|
$ |
21,449 |
|
|
$ |
36,051 |
|
|
$ |
37,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Payments Received |
|
|
|
January |
|
|
April |
|
|
July |
|
|
October |
|
Royalty
payment as
calculated |
|
$ |
65,284 |
|
|
$ |
57,859 |
|
|
$ |
66,030 |
|
|
$ |
61,429 |
|
Adjustment for
underpayment
(overpayment), plus
accrued interest |
|
|
64 |
|
|
|
|
|
|
|
|
|
|
|
1,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net payment received |
|
$ |
65,348 |
|
|
$ |
57,859 |
|
|
$ |
66,030 |
|
|
$ |
63,061 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 Payments Received |
|
|
|
January |
|
|
April |
|
|
July |
|
|
October |
|
Royalty payment as
calculated |
|
$ |
41,470 |
|
|
$ |
39,297 |
|
|
$ |
44,164 |
|
|
$ |
49,636 |
|
Adjustment for
underpayment
(overpayment), plus
accrued interest |
|
|
1,736 |
|
|
|
(47 |
) |
|
|
|
|
|
|
1,062 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net payment received |
|
$ |
43,206 |
|
|
$ |
39,250 |
|
|
$ |
44,164 |
|
|
$ |
50,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In January 2010, the Trust received a payment of $48,020,080 from BP Alaska. This payment
consisted of $47,862,529, representing the royalty payment due with respect to the Trusts
Royalty Interest for the quarter ended December 31, 2009, plus $158,551, 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, 2009. On January 20, 2010, after deducting
Trust administrative expenses, the Trustee distributed $77,294,472 from the January 2010 royalty
payment and the settlement amount received in December 2009 (approximately $3.61 per Unit) to
Unit holders of record on January 15, 2010. See Note 7 above. |
|
|
|
Subsequent events have been evaluated through the date of the
annual report on Form 10-K in
which these financial statements are included. |
40
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
(10) |
|
Summary of Quarterly Results (Unaudited) |
|
|
A summary of selected quarterly financial information for the years ended December 31, 2009,
2008, and 2007 is as follows (in thousands, except unit data): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Fiscal Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
Royalty revenues |
|
$ |
35,280 |
|
|
$ |
21,449 |
|
|
$ |
36,051 |
|
|
$ |
37,234 |
|
Settlement revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,474 |
|
Interest income |
|
|
2 |
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
Trust administrative expenses |
|
|
(269 |
) |
|
|
(224 |
) |
|
|
(746 |
) |
|
|
(220 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
35,013 |
|
|
|
21,225 |
|
|
|
35,306 |
|
|
|
66,489 |
|
Cash distributions |
|
|
35,031 |
|
|
|
21,225 |
|
|
|
35,305 |
|
|
|
37,014 |
|
Cash distributions per unit |
|
|
1.6369 |
|
|
|
0.9918 |
|
|
|
1.6498 |
|
|
|
1.7296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Fiscal Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
Royalty revenues |
|
$ |
65,348 |
|
|
$ |
57,859 |
|
|
$ |
66,030 |
|
|
$ |
63,061 |
|
Interest income |
|
|
19 |
|
|
|
7 |
|
|
|
3 |
|
|
|
4 |
|
Trust administrative expenses |
|
|
(183 |
) |
|
|
(738 |
) |
|
|
(689 |
) |
|
|
(187 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
65,184 |
|
|
|
57,128 |
|
|
|
65,344 |
|
|
|
62,878 |
|
Cash distributions |
|
|
65,182 |
|
|
|
57,137 |
|
|
|
65,344 |
|
|
|
62,862 |
|
Cash distributions per unit |
|
|
3.0459 |
|
|
|
2.6699 |
|
|
|
3.0535 |
|
|
|
2.9375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year Ended |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Royalty revenues |
|
$ |
130,014 |
|
|
$ |
252,298 |
|
|
$ |
177,318 |
|
Settlement revenue |
|
|
29,474 |
|
|
|
|
|
|
|
|
|
Interest income |
|
|
4 |
|
|
|
33 |
|
|
|
81 |
|
Trust administrative expenses |
|
|
(1,459 |
) |
|
|
(1,797 |
) |
|
|
(1,687 |
) |
|
|
|
|
|
|
|
|
|
|
Cash earnings |
|
|
158,033 |
|
|
|
250,534 |
|
|
|
175,712 |
|
Cash distributions |
|
|
128,575 |
|
|
|
250,525 |
|
|
|
175,713 |
|
Cash distributions per unit |
|
|
6.008 |
|
|
|
11.7068 |
|
|
|
8.211 |
|
41
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
(11) |
|
Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flow
Relating to Proved Reserves (Unaudited) |
|
|
Pursuant to Statement of FASB ASC 932, Extractive Activities Oil and Gas, 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. The following
information in this note with respect to the year ended December 31, 2009 reflects the adoption
of Securities Exchange Act Release No. 59192, Modernization of Oil and Gas Reporting which
became effective for financial statements for fiscal years ending on or after December 31, 2009.
The Trust has not restated reserve information with respect to the years ended December 31, 2007
and 2008 to reflect changes in the methodology for determining proved reserves prescribed by
Release No. 59192. |
|
|
|
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
Prudhoe Bay 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 12-month average WTI
Price for 2009 ($61.18 per barrel), and on the WTI Price on December 31, 2008 ($44.60 per
barrel) and December 31, 2007 ($96.01 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,
2009, 2008 and 2007, based on BP Alaskas latest reserve estimate at such time and the 12-month
average WTI price for 2009 and WTI Prices on December 31, 2008 and 2007, were estimated to be
68, 55 and 98 million barrels, respectively (of which 57, 46 and 87 million barrels,
respectively, are proved developed reserves). Under the provisions of FASB ASC 932, 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 ASC 932 assigns monetary amounts to proved reserves based on current
prices. This discounted future net cash flow should not be construed as the current market value
of the Royalty Interest. A market valuation determination would include, among other things,
anticipated price changes and the value of additional reserves not considered proved at the present time or
reserves that may be produced after the currently anticipated end of field life. At December 31,
2009, 2008 and 2007, 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
ASC 932), |
42
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
|
|
based on the 12-month average WTI Price for 2009 of $61.18 per barrel and the WTI
Prices on December 31, 2008 and 2007 of $44.60 and $96.01 per barrel, respectively, were as
follows (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Future cash inflows |
|
$ |
1,331,319 |
|
|
$ |
632,470 |
|
|
$ |
3,209,305 |
|
10% annual discount for
estimated timing of cash flows |
|
|
(494,758 |
) |
|
|
(213,900 |
) |
|
|
(1,609,463 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future
net cash flow (a) |
|
$ |
836,561 |
|
|
$ |
418,570 |
|
|
$ |
1,599,842 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The following are the principal sources of the change in the standardized measure of
discounted future net cash flows (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Revisions of prior estimates |
|
$ |
(17,629 |
) |
|
$ |
(17,490 |
) |
|
$ |
64,461 |
|
Net changes in prices and production costs |
|
|
714,714 |
|
|
|
(1,969,952 |
) |
|
|
1,364,445 |
|
Net change in production taxes |
|
|
(173,810 |
) |
|
|
879,903 |
|
|
|
(778,644 |
) |
Other |
|
|
2,581 |
|
|
|
168 |
|
|
|
1,608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
525,856 |
|
|
|
(1,107,371 |
) |
|
|
651,870 |
|
Royalty income received (b) |
|
|
(149,722 |
) |
|
|
(233,885 |
) |
|
|
(209,172 |
) |
Accretion of discount |
|
|
41,857 |
|
|
|
159,984 |
|
|
|
105,195 |
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) during the year |
|
$ |
417,991 |
|
|
$ |
(1,181,272 |
) |
|
$ |
547,893 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) |
|
For the purpose of this calculation, royalty income received
for 2009, 2008 and 2007
includes the following: |
|
|
|
|
|
Period October 1, 2009 through December 31, 2009 |
|
$ |
48,021 |
|
Period October 1, 2008 through December 31, 2008 |
|
$ |
35,280 |
|
Period October 1, 2007 through December 31, 2007 |
|
$ |
65,182 |
|
|
|
The above royalty income was received by the Trust in January 2010, 2009 and 2008, respectively. |
43
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
The changes in estimated quantities of proved oil and condensate were as follows:
Proved developed and undeveloped reserves (thousands of barrels) as of:
|
|
|
|
|
December 31, 2006 |
|
|
81,078 |
|
Revisions of previous estimates (1) |
|
|
21,970 |
|
Production |
|
|
(5,249 |
) |
|
|
|
|
December 31, 2007 |
|
|
97,799 |
|
Revisions of previous estimates (2) |
|
|
(37,988 |
) |
Production |
|
|
(4,857 |
) |
|
|
|
|
December 31, 2008 |
|
|
54,954 |
|
Revisions of previous estimates (3) |
|
|
18,419 |
|
Production |
|
|
(5,229 |
) |
|
|
|
|
December 31, 2009 |
|
|
68,144 |
|
|
|
|
|
|
|
|
|
|
Proved developed reserves (thousands of barrels) as of: |
|
|
|
|
December 31, 2007 |
|
|
86,869 |
|
December 31, 2008 |
|
|
46,096 |
|
December 31, 2009 |
|
|
57,077 |
|
|
|
|
|
|
Proved undeveloped reserves (thousands of barrels) as of: |
|
|
|
|
December 31, 2007 |
|
|
10,930 |
|
December 31, 2008 |
|
|
8,858 |
|
December 31, 2009 |
|
|
11,067 |
|
|
|
|
(1) |
|
The positive revision in year-end 2007 reserves reflects an increase in the WTI
price from $61.06 per barrel at December 31, 2006 to $96.01 per barrel at December 31,
2007. |
|
(2) |
|
The negative revision in year-end 2008 reserves reflects a decrease in the WTI
price from $96.01 per barrel at December 31, 2007 to $44.60 per barrel at December 31,
2008. |
|
(3) |
|
The positive revision in year-end 2009 reserves reflects an increase in the WTI
price from $44.60 per barrel at December 31, 2008 to $61.18 per barrel using the 12-month
average of the first-day-of-the-month price for each month in the year ended December 31,
2009 |
44
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, 2009.
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 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 1989 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 2009, 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.
45
Internal Control Over Financial Reporting
Managements Annual Report on Internal Control Over Financial Reporting. The Bank of New York
Mellon, 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, 2009.
The Trustees assessment of the effectiveness of the Trusts internal control over financial
reporting as of December 31, 2009 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 BP Prudhoe Bay Royalty Trusts (the Trust) internal control over financial
reporting as of December 31, 2009, 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 Mellon (formerly named The Bank of New York), as the Trusts trustee (the
Trustee), 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 Managements Annual Report 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.
46
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, BP Prudhoe Bay Royalty Trust maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, 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, 2009 and 2008, 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, 2009, and our report dated March 1, 2010 expressed an unqualified opinion on those
financial statements.
KPMG LLP
Dallas, Texas
March 1, 2010
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 Code of Conduct which may be found at
http://www.bnymellon.com/ethics.
47
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, 2009 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfer Agent and |
|
Year ended December 31, |
|
Trustees Fees |
|
|
Registrar Fees |
|
2007 |
|
$ |
172,235 |
* |
|
$ |
6,494 |
|
2008 |
|
|
155,432 |
|
|
|
6,391 |
|
2009 |
|
|
155,431 |
|
|
|
6,096 |
|
|
|
|
* |
|
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 26, 2010, 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 Mellon, as Trustee or in its individual capacity, or by BNY Mellon Trust of Delaware), as
co-trustee or in its individual capacity.
48
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 2009, 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, 2009 and 2008 are:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Audit |
|
$ |
151,216 |
|
|
$ |
163,386 |
|
Audit related |
|
|
20,000 |
|
|
|
20,000 |
|
Tax |
|
|
200,000 |
|
|
|
200,000 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
371,216 |
|
|
$ |
383,386 |
|
|
|
|
|
|
|
|
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, 2009 and 2008
Statements of Cash Earnings and Distributions for the years ended December 31, 2009, 2008 and 2007
Statements of Changes in Trust Corpus for the years ended December 31, 2009, 2008 and 2007
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.
49
(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. |
|
|
|
10.1
|
|
Settlement Agreement, dated May 8, 2009, among BP Exploration (Alaska) Inc., The Bank of New
York Mellon, as Trustee, and BNY Mellon Trust Company of Delaware, as Co-Trustee. |
|
|
|
31
|
|
Rule 13a-14(a) certification. |
|
|
|
32
|
|
Section 1350 certification. |
|
|
|
99
|
|
Report of Miller and Lents, Ltd., dated February 19, 2010. |
50
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 MELLON, as Trustee
|
|
|
|
|
By: |
/s/ Geovanni Barris
|
|
|
|
Geovanni Barris |
|
|
|
Vice President |
|
|
March 1, 2010
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.
51
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). |
|
|
|
4.6
|
|
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). |
|
|
|
10.1
|
|
Settlement Agreement, dated May 8, 2009, among BP Exploration (Alaska) Inc., The Bank of New
York Mellon, as Trustee, and BNY Mellon Trust Company of Delaware, as Co-Trustee. Incorporated
by reference to the correspondingly numbered exhibit to the Registrants Current Report on
Form 8-K dated May 8, 2009 (File No. 1-10243). |
|
|
|
31*
|
|
Rule 13a-14(a) certification. |
|
|
|
32*
|
|
Section 1350 certification. |
|
|
|
99*
|
|
Report of Miller and Lents, Ltd., dated February 19, 2010. |