BP PRUDHOE BAY ROYALTY TRUST - Annual Report: 2005 (Form 10-K)

BP Prudhoe Bay Royalty Trust 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year ended December 31, 2005


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-10243

BP PRUDHOE BAY ROYALTY TRUST

(Exact name of registrant as specified in its charter)


DELAWARE
State or other jurisdiction		13-6943724
of incorporation or organization)		(I.R.S. Employer Identification No.)


THE BANK OF NEW YORK, TRUSTEE
101 BARCLAY STREET
NEW YORK, NEW YORK		10286
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (212) 815-6908

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Each Exchange on Which Registered

UNITS OF BENEFICIAL INTEREST		NEW YORK STOCK EXCHANGE

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No þ

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated filer þ Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act Yes o No þ

The aggregate market value of Units held by nonaffiliates (computed by reference to the closing sale price in New York Stock Exchange transactions on June 30, 2005 (the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $1,531,598,000.

As of March 16, 2006, 21,400,000 Units of Beneficial Interest were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS


PART I			1

ITEM 1. BUSINESS			1

INTRODUCTION			1
THE TRUST			1
THE ROYALTY INTEREST			6
THE UNITS			8
THE BP SUPPORT AGREEMENT			10
THE PRUDHOE BAY UNIT AND FIELD			11
INDEPENDENT OIL AND GAS CONSULTANTS’ REPORT			16
INDUSTRY CONDITIONS AND REGULATIONS			21
CERTAIN TAX CONSIDERATIONS			21

ITEM 2. PROPERTIES			23

ITEM 1A. RISK FACTORS			23

ITEM 1B. UNRESOLVED STAFF COMMENTS			26

ITEM 3. LEGAL PROCEEDINGS			26

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			26

PART II			26

ITEM 5. MARKET FOR REGISTRANT’S UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS			26

ITEM 6. SELECTED FINANCIAL DATA			27

ITEM 7. TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			27

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			29

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			30

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			42

ITEM 9A. CONTROLS AND PROCEDURES			42

ITEM 9B. OTHER INFORMATION			44


PART III			44

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT			44

ITEM 11. EXECUTIVE COMPENSATION			45

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			45

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			45

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES			46

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES			46

SIGNATURES			48
EX-31 Certification
EX-32

PART I

ITEM 1. BUSINESS

INTRODUCTION

BP Prudhoe Bay Royalty Trust (the “Trust”) was created as a Delaware business trust by the BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 (the “Trust Agreement”) among The Standard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”), The Bank of New York, as trustee (the “Trustee”), and F. James Hutchinson, co-trustee (The Bank of New York (Delaware), successor co-trustee). BP Alaska and Standard Oil are wholly owned subsidiaries of BP p.l.c. (“BP”). The Trustee’s 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 SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers (including the Trust) that file electronically with the SEC. The address of the SEC’s web site is http://www.sec.gov.

The Trust does not have an Internet web site from which information concerning the Trust may be obtained; however the Trustee will provide paper or electronic copies of the Trust’s reports on Form 10-K, Form 10-Q and Form 8-K, and amendments to those reports, free of charge upon request as soon as reasonably practicable after the Trust files them with the SEC. Requests for copies of reports may be made by mail to: The Bank of New York, 101 Barclay Street, New York, NY 10286, Attention: Mr. Remo Reale, Corporate Trust Department; by telephone to: (212) 815-6908; or by e-mail to: rreale@bankofny.com.

The information in this report relating to the Prudhoe Bay Unit, the calculation of royalty payments and certain other matters has been furnished to the Trustee by BP Alaska.

Forward-Looking Statements

Various sections of this report contain forward-looking statements (that is, statements anticipating future events or conditions and not statements of historical fact). Words such as “anticipate,” “expect,” “believe,” “intend,” “plan” or “project,” and “should,” “would,” “could,” “potentially,” “possibly” or “may,” and other words that convey uncertainty of future events or outcomes are intended to identify forward-looking statements. Forward-looking statements in this report are subject to a number of risks and uncertainties beyond the control of the Trustee. These risks and uncertainties include such matters as future changes in oil prices, oil production levels, economic activity, domestic and international political events and developments, legislation and regulation, and certain changes in expenses of the Trust.

The actual results, performance and prospects of the Trust could differ materially from those expressed or implied by forward-looking statements. Descriptions of some of the risks that could affect the future performance of the Trust appear in the following Item 1A, “Risk Factors,” and elsewhere in

this report. There may be additional risks of which the Trustee is unaware or which are currently deemed immaterial.

In the light of these risks, uncertainties and assumptions, you should not rely unduly on any forward-looking statements. Forward-looking events and outcomes discussed in this report may not occur or may transpire differently. The Trustee undertakes no obligation to update forward-looking statements after the date of this report, except as required by law, and all such forward-looking statements in this report are qualified in their entirety by the preceding cautionary statements.

THE TRUST

Trust Property

The property of the Trust consists of an overriding royalty interest (the “Royalty Interest”) and cash and cash equivalents held by the Trustee from time to time. The Royalty Interest entitles the Trust to a royalty on 16.4246 percent of the first 90,000 barrels^* of the average actual daily net production of oil and condensate per quarter from the working interest of BP Alaska as of February 28, 1989 in the Prudhoe Bay oil field located on the North Slope in Alaska. The Prudhoe Bay field is one of four contiguous North Slope oil fields that are operated by BP Alaska and are known collectively as the Prudhoe Bay Unit. The Royalty Interest was conveyed to the Trust by an Overriding Royalty Conveyance dated February 27, 1989 from BP Alaska to Standard Oil and a Trust Conveyance dated February 28, 1989 from Standard Oil to the Trust. Copies of the Overriding Royalty Conveyance and the Trust Conveyance are filed with the SEC as exhibits to this report. The Overriding Royalty Conveyance and the Trust Conveyance are referred to collectively as the “Conveyance.”

The Royalty Interest is a non-operational interest in minerals. The Trust does not have the right to take oil and gas in kind, nor does it have any right to take over operations or to share in any operating decision with respect to BP Alaska’s working interest in the Prudhoe Bay field. BP Alaska is not obligated to continue to operate any well or maintain or attempt to maintain in force any portion of its working interest when, in its reasonable and prudent business judgment, the well or interest ceases to produce or is not capable of producing oil or gas in paying quantities.

Employees

The Trust has no employees. All administrative functions of the Trust are performed by the Trustee.

Duties and Powers of the Trustee

The duties of the Trustee are specified in the Trust Agreement and the laws of the State of Delaware. The Bank of New York (Delaware) has been appointed co-trustee in order to satisfy certain requirements of the Delaware Trust Act, but The Bank of New York alone is able to exercise the rights and powers granted to the Trustee in the Trust Agreement. A copy of the Trust Agreement is filed as an exhibit to this report and is available upon request from the Trustee.

The basic function of the Trustee is to collect income from the Royalty Interest, to pay all expenses, charges and obligations of the Trust from the Trust’s income and assets, and to pay available


^*		The term “barrel” is a unit of measure of petroleum liquids equal to 42 United States gallons corrected to 60 degrees Fahrenheit temperature.

cash to Unit holders. Because of the passive nature of the Trust’s assets and the restrictions on the power of the Trustee to incur obligations, the only liabilities incurred by the Trust are the Trustee’s fees and routine administrative expenses, including accounting, legal and other professional fees.

The Trust Agreement grants the Trustee only the rights and powers necessary to achieve the purposes of the Trust. The Trust Agreement prohibits the Trust from engaging in any business or commercial activity or, with certain exceptions, any investment activity and from using any assets of the Trust to acquire any oil and gas lease, royalty or other mineral interest.

Except in certain circumstances, the Trustee is entitled to be indemnified out of the assets of the Trust for any liability or loss incurred by it in the performance of its duties unless the loss results from its negligence, bad faith or fraud or from expenses incurred in carrying out its duties that exceed the compensation and reimbursement to which it is entitled under the Trust Agreement.

Sales of Assets, Borrowings and Reserves

With certain exceptions, the Trustee may sell Trust assets only if authorized to do so by vote of the holders of 70 percent of the Units outstanding. However, if the sale is made in order to pay specific liabilities of the Trust then due and involves a part, but not all or substantially all, of the Trust properties, the sale only needs to be approved by the vote of holders of a majority of the Units. Any sale of Trust properties must be for cash unless otherwise authorized by the Unit holders. The Trustee is obligated to distribute the available net proceeds of any such sale to the Unit holders after establishing reserves for liabilities of the Trust.

The Trustee has the power to borrow on behalf of the Trust or to sell Trust assets to pay liabilities of the Trust and to establish a reserve for the payment of liabilities without the consent of the Unit holders under the following circumstances:

The Trustee may borrow from a lender not affiliated with the Trustee, if cash on hand is not sufficient to pay current liabilities, it is not practical to pay such liabilities out of funds anticipated to be available in a subsequent quarter, and failure to pay the liabilities would subject the Trust property to the risk of loss or diminution in value. To secure payment of its borrowings on behalf of the Trust, the Trustee is authorized to encumber the Trust’s assets, and to carve out and convey production payments. The borrowing must be on terms which (in the opinion of an investment banking firm or commercial banking firm) are commercially reasonable when compared to other available alternatives. No distributions to Unit holders may be made until the borrowings by the Trust have been repaid in full.

If the Trustee is unable to borrow to pay Trust liabilities, the Trustee may sell Trust assets if it determines that the failure to pay the liabilities at a later date will be contrary to the best interest of the Unit holders and that it is not practicable to submit the sale to a vote of the Unit holders. The sale must be made for cash at a price which (in the opinion of an investment banking firm or commercial banking firm) is at least equal to the fair market value of the interest sold and is made on commercially reasonable terms when compared to other available alternatives.

The Trustee has the right to establish a cash reserve for the payment of material liabilities of the Trust which may become due if it determines that it is not practical to pay such liabilities out of funds anticipated to be available and that, in the absence of a reserve, the Trust

property is subject to the risk of loss or diminution in value, or the Trustee is subject to the risk of personal liability for such liabilities.

In order for the Trustee to borrow, sell assets to pay Trust liabilities or establish a reserve for Trust liabilities, the Trustee must receive an unqualified written legal opinion that the action will not adversely affect the classification of the Trust as a “grantor trust” for federal income tax purposes or cause the income from the Trust to be treated as unrelated business taxable income for federal income tax purposes. If the Trustee is unable to obtain the required legal opinion, it still may proceed with the borrowing or sale, or establish the reserve, if it determines that the failure to do so will be materially detrimental to the Unit holders considered as a whole or will subject the Trustee to the risk of personal liability for liabilities of the Trust.

In 1999, the Trustee established a $1,000,000 cash reserve to provide liquidity to the Trust during any future periods in which the Trust does not receive a distribution from BP Alaska. See Item 7 in Part II below.

Amendment of the Trust Agreement

The Trust Agreement may be amended without a vote of the Unit holders to cure an ambiguity, to correct or supplement any provision of the Trust Agreement that may be inconsistent with any other provision or to make any other provision with respect to matters arising under the Trust Agreement that do not adversely affect the Unit holders. The Trust Agreement may also be amended with the approval of holders of a majority of the outstanding Units. However, no such amendment may alter the relative rights of Unit holders, unless approved by the affirmative vote of holders of 100 percent of the outstanding Units and by the Trustee, or reduce or delay the distributions to the Unit holders or make certain other changes unless approved by the affirmative vote of holders of at least 80 percent of the outstanding Units and by the Trustee. No amendment will be effective until the Trustee has received a ruling from the Internal Revenue Service or an opinion of counsel to the effect that such modification will not adversely affect the classification of the Trust as a “grantor trust” for federal income tax purposes or cause the income from the Trust to be treated as unrelated business taxable income for federal income tax purposes.

Resignation or Removal of Trustee

The Trustee may resign at any time or be removed with or without cause by the holders of a majority of the outstanding Units. Its successor must be a corporation organized, doing business and authorized to exercise trust powers under the laws of the United States, any state thereof or the District of Columbia, or a national banking association domiciled in the United States, in either case having a combined capital, surplus and undivided profits of at least $50,000,000 and subject to supervision or examination by federal or state authorities. Unless the Trust already has a trustee that is a resident of or has a principal office in Delaware, any successor trustee must be a resident of Delaware or have a principal office in Delaware. No resignation or removal of the Trustee will become effective until a successor trustee has accepted appointment.

Termination of the Trust

The Trust is irrevocable. BP Alaska has no power to terminate the Trust. The Trust will terminate: (a) on or before December 31, 2010 if holders of at least 70 percent of the outstanding Units vote to terminate the Trust, or (b) after December 31, 2010 either (i) holders at least 60 percent of the outstanding Units vote to terminate the Trust or (ii) the net revenues from the Royalty Interest for two

successive years commencing after 2010 are less than $1,000,000 per year (unless the net revenues during the two-year period have been materially and adversely affected by certain extraordinary events).

Upon termination of the Trust, BP Alaska will have an option to purchase the Royalty Interest at a price equal to the greater of (i) the fair market value of the Trust property as set forth in an opinion of an investment banking firm, commercial banking firm or other entity qualified to give an opinion as to the fair market value of the assets of the Trust, or (ii) the number of outstanding Units multiplied by (a) the closing price of Units on the day of termination of the Trust on the stock exchange on which the Units are listed, or (b) if the Units are not listed on any stock exchange but are traded in the over-the-counter market, the closing bid price on the day of termination of the Trust as quoted on the NASDAQ National Market System. The purchase must be for cash unless holders of 70 percent of the Units outstanding (60 percent if the decision to terminate the Trust is made after December 31, 2010) authorize the sale for non-cash consideration and the Trustee has received a ruling from the Internal Revenue Service or an opinion of counsel to the effect that such non-cash sale will not adversely affect the classification of the Trust as a “grantor trust” for federal income tax purposes or cause the income from the Trust to be treated as unrelated business taxable income for federal income tax purposes.

If BP Alaska does not exercise its option, the Trustee will sell the Trust properties on terms and conditions approved by the vote of holders of 70 percent of the outstanding Units (60 percent if the sale is made after December 31, 2010), unless the Trustee determines that it is not practicable to submit the matter to a vote of the Unit holders, and the sale is made at a price at least equal to the fair market value of the Trust property as set forth in the opinion mentioned above and on terms and conditions deemed commercially reasonable by the investment banking firm, commercial banking firm or other entity rendering the opinion.

The Trustee will distribute all available proceeds to the Unit holders after satisfying all existing liabilities of the Trust and establishing adequate reserves for the payment of contingent liabilities.

In the Trust Agreement, Unit holders have waived the right to seek or secure any portion or distribution of the Royalty Interest or any other asset of the Trust or any accounting during the term of the Trust or during any period of liquidation and winding up.

Voting Rights of Unit Holders

Unit holders possess certain voting rights, but their voting rights are not comparable to those of shareholders of a corporation. For example, there is no requirement for annual meetings of Unit holders or for periodic reelection of the Trustee.

A meeting of the Unit holders may be called at any time to act with respect to any matter as to which the Trust Agreement authorizes the Unit holders to act. Any such meeting may be called by the Trustee in its discretion and will be called (i) as soon as practicable after receipt of a written request by BP Alaska or a written request that sets forth in reasonable detail the action proposed to be taken at the meeting and is signed by holders of at least 25 percent of the outstanding Units or (ii) when required by applicable laws or regulations or the New York Stock Exchange. All meetings of Unit holders are required to be held in Manhattan, New York City.

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 Alaska’s working interest in the Prudhoe Bay Unit for the quarter, net of the State of Alaska royalty and less the value of any applicable payments made to affiliates of BP Alaska.

Royalty Production

The “Royalty Production” for each day in a calendar quarter is 16.4246 percent of the first 90,000 barrels of the actual average daily net production of oil and condensate for the quarter from the Prudhoe Bay (Permo-Triassic) Reservoir and allocated to the oil and gas leases owned by BP Alaska in the Prudhoe Bay Unit as of February 28, 1989 (the “BP Working Interests”). The Royalty Production is based on oil produced from the oil rim and condensate produced from the gas cap, but not on gas production or natural gas liquids production. The actual average daily net production of oil and condensate from the BP Working Interests for any calendar quarter is the total production of oil and condensate for the quarter, net of the State of Alaska royalty, divided by the number of days in the quarter.

Per Barrel Royalty

The “Per Barrel Royalty” for any day is the WTI Price for the day less the sum of (i) Chargeable Costs multiplied by the Cost Adjustment Factor and (ii) Production Taxes.

WTI Price

The “WTI Price” for any trading day is (i) the price (in dollars per barrel) for West Texas intermediate crude oil of standard quality having a specific gravity of 40 API degrees for delivery at Cushing, Oklahoma (“West Texas Crude”) quoted for that trading day by whichever of The Wall Street Journal, Reuters, or Platts Oilgram Price Report, in that order, publishes West Texas Crude price quotations for the trading day, or (ii) if the price of West Texas Crude is not published by one of those publications, the WTI Price will be the simple average of the daily mean prices (in dollars per barrel) quoted for West Texas Crude by one major oil company, one petroleum broker and one petroleum trading company designated by BP Alaska, in each case unaffiliated with BP and having substantial U.S. operations, until published price quotations are again available. If prices for West Texas Crude are not quoted so as to permit the calculation of the WTI Price, the price of “West Texas Crude,” for the purposes of calculating the WTI Price will be the price of another light sweet domestic crude oil of standard quality designated by BP Alaska and approved by the Trustee, with appropriate allowance for transportation costs to the Gulf coast (or another appropriate location) to equilibrate its price to the WTI Price. The WTI Price for any day which is not a trading day is the WTI Price for the preceding trading day.

Chargeable Costs

The “Chargeable Costs” per barrel of Royalty Production for each calendar year are fixed amounts specified in the Conveyance and do not necessarily represent BP Alaska’s actual costs of

production. Chargeable Costs per barrel were $10.75 during 2001, $11.25 during 2002, $11.75 during 2003, $12.00 during 2004, and $12.25 during 2005. Chargeable Costs for 2006 and subsequent years are shown in the following table:


Calendar	Chargeable Costs		Calendar		Chargeable Costs
year	per barrel		year		per barrel
2006	$	12.50		2014	$	16.90
2007		12.75		2015		17.00
2008		13.00		2016		17.10
2009		13.25		2017		17.20
2010		14.50		2018		20.00
2011		16.60		2019		23.75
2012		16.70		2020		26.50
2013		16.80

After 2020, Chargeable Costs increase at a uniform rate of $2.75 per year.

Cost Adjustment Factor

The “Cost Adjustment Factor” for a quarter is the ratio of the Consumer Price Index published for the most recently past February, May, August or November to 121.1 (the Consumer Price Index for January 1989). The “Consumer Price Index” is the U.S. Consumer Price Index, all items and all urban consumers, U.S. city average (1982-84 equals 100), as first published, without seasonal adjustment, by the Bureau of Labor Statistics, Department of Labor, without regard to subsequent revisions or corrections. If the average WTI Price for any calendar quarter falls to $18.00 or less, the Cost Adjustment Factor for that quarter will be the Cost Adjustment Factor for the immediately preceding quarter. If the average WTI Price returns to more than $18.00 for a later quarter, adjustments to the Cost Adjustment Factor resume, but with an adjustment to the formula that excludes changes in the Consumer Price Index during the period that adjustments to the Cost Adjustment Factor were suspended.

Production Taxes

“Production Taxes” are the sum of any severance taxes, excise taxes (including windfall profit tax, if any), sales taxes, value added taxes or other similar or direct taxes imposed upon the reserves or production, delivery or sale of Royalty Production, computed at defined statutory rates. In the case of taxes based upon wellhead or field value, the Conveyance provides that the WTI Price less the product of $4.50 and the Cost Adjustment factor will be deemed to be the wellhead or field value. At the present time, the Production Taxes payable with respect to the Royalty Production are the Alaska Oil and Gas Properties Production Tax (“Alaska Production Tax”). For the purposes of the Royalty Interest, the Alaska Production Tax is computed without regard to the “economic limit factor,” if any, as the greater of the “percentage of value amount” (based on the statutory rate and the wellhead value as defined above) and the “cents per barrel amount.” As of the date of this report, the statutory rate for the purpose of calculating the “percentage of value amount” is 15 percent. In February 2006, the Governor of Alaska proposed legislation that would replace the Alaska Production Tax with a net profits tax on producers (see Item 1A below). A surcharge to the Alaska Production Tax increased Production Taxes by $0.05 per barrel of net production in 1989. Due to the spill response fund having reached $50 million in 1995, $0.02 per barrel of the surcharge has been indefinitely suspended. If the balance of the spill response fund falls below $50 million, the $0.02 per barrel surcharge will be reinstated until the fund balance again reaches $50 million. The remaining $0.03 per barrel surcharge is not affected by the fund’s balance and will continue to be imposed at all times.

Per Barrel Royalty Calculations

The following table shows how the above-described factors interacted during the past five years to produce the Per Barrel Royalty paid for the calendar quarters indicated.


					Cost		Adjusted
	Average		Chargeable		Adjustment		Chargeable		Production		Per Barrel
	WTI Price		Costs		Factor		Costs		Taxes		Royalty
2001:
1^st Qtr	$	28.83	$	10.75		1.354	$	14.55	$	3.44	$	10.84
2^nd Qtr		27.92		10.75		1.368		14.71		3.29		9.92
3^rd Qtr		26.82		10.75		1.367		14.69		3.13		9.00
4^th Qtr		20.41		10.75		1.366		14.68		2.17		3.56

2002:
1^st Qtr		21.67		11.25		1.369		15.40		2.36		3.91
2^nd Qtr		26.28		11.25		1.384		15.57		3.04		7.67
3^rd Qtr		28.33		11.25		1.391		15.65		3.34		9.34
4^th Qtr		28.25		11.25		1.396		15.70		3.33		9.22

2003:
1^st Qtr		34.08		11.75		1.410		16.57		4.19		13.32
2^nd Qtr		29.07		11.75		1.413		16.60		3.44		9.03
3^rd Qtr		30.30		11.75		1.421		16.70		3.62		9.98
4^th Qtr		31.23		11.75		1.421		16.69		3.76		10.78

2004:
1^st Qtr		35.18		12.00		1.434		17.20		4.34		13.64
2^nd Qtr		38.31		12.00		1.456		17.47		4.79		16.05
3^rd Qtr		43.78		12.00		1.459		17.51		5.61		20.66
4^th Qtr		48.35		12.00		1.471		17.65		6.29		24.41

2005:
1^st Qtr		49.70		12.25		1.477		18.09		6.49		25.12
2^nd Qtr		53.09		12.25		1.497		18.34		6.98		27.77
3^rd Qtr		63.03		12.25		1.512		18.53		8.46		36.04
4^th Qtr		60.01		12.25		1.521		18.63		8.01		33.37

THE UNITS

Units

Each Unit represents an equal undivided share of beneficial interest in the Trust. The Units do not represent an interest in or an obligation of BP Alaska, Standard Oil or any of their respective affiliates. Units are evidenced by transferable certificates issued by the Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit. The Trust has no other authorized or outstanding class of securities.

Distributions of Income

BP Alaska makes quarterly payments to the Trust of the amounts due with respect to the Trust’s Royalty Interest on the fifteenth day following the end of each calendar quarter or, if the fifteenth is not a business day, on the next succeeding business day (the “Quarterly Record Date”). The Trustee 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 Trust’s expenses, net of any additions to or subtractions from the cash reserve established for the payments of estimated liabilities (the “Quarterly Distribution”), to the persons in whose names the Units were registered at the close of business on the Quarterly Record Date.

The Trust Agreement requires the Trustee to pay the Quarterly Distribution to Unit holders on the fifth day after the Trustee’s receipt of the amount paid by BP Alaska. Cash balances held by the Trustee for distribution are required to be invested in United States government or agency obligations secured by the full faith and credit of the United States (“Government Obligations”) or, if Government Obligations that mature on the date of the distribution to Unit holders are not available, in repurchase agreements with banks having capital, surplus and undivided profits of $100,000,000 or more (which may include The Bank of New York) secured by Government Obligations. If time does not permit the Trustee to invest collected funds in Government Obligations or repurchase agreements, the Trustee may invest funds overnight in a time deposit with a bank meeting the foregoing capital requirement (including The Bank of New York).

Reports to Unit Holders

After the end of each calendar year, the Trustee mails a report to the persons who held Units of record during the year containing information to enable them to make the calculations necessary for federal and Alaska income tax purposes, including the calculation of any depletion or other deduction which may be available to them for the calendar year. In addition, after the end of each calendar year the Trustee mails Unit holders an annual report containing a copy of this Form 10-K and certain other information required by the Trust Agreement.

Limited Liability of Unit Holders

The Trust Agreement provides that the Unit holders are, to the full extent permitted by Delaware law, entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under Delaware law.

Possible Divestiture of Units

The Trust Agreement imposes no restrictions on nationality or other status of the persons eligible to hold Units. However, it provides that if at any time the Trust or the Trustee is named a party in any judicial or administrative proceeding seeking the cancellation or forfeiture of any property in which the Trust has an interest because of the nationality, or any other status, of any one or more Unit holders, the Trustee may require each holder whose nationality or other status is an issue in the proceeding to dispose of his Units to a party not of the nationality or other status at issue in the proceeding. If any holder fails to dispose of his Units within 30 days after receipt of notice from the Trustee to do so, the Trustee will

redeem any Unit not so transferred within 90 days after the end of the 30-day period specified in the notice for a cash price per Unit equal to the fair market value of the Units. Units redeemed by the Trustee will be cancelled.

The Trustee may cause the Trust to borrow any amount required to redeem the Units. If the purchase of Units from an ineligible holder by the Trustee would result in a non-exempt “prohibited transaction” under the Employee Retirement Income Security Act of 1970, or under the Internal Revenue Code of 1986, the Units subject to the Trustee’s right of redemption will be purchased by BP Alaska or a designee of BP Alaska.

Issuance of Additional Units

The Trust Agreement provides that BP Alaska or an affiliate from time to time may assign to the Trust additional royalty interests meeting certain conditions and, upon satisfaction of various other conditions, the Trust may issue up to an additional 18,600,000 Units. BP Alaska has not conveyed any additional royalty interests to the Trust, and the Trust has not issued any additional Units.

THE BP SUPPORT AGREEMENT

BP has agreed to provide financial support to BP Alaska in meeting its payment obligations to the Trust in a Support Agreement dated February 28, 1989 among BP, BP Alaska, Standard Oil and the Trust (the “Support Agreement”). Within 30 days after it receives notice, BP will ensure that BP Alaska can perform its payment obligations under the Trust Agreement and the Conveyance, including contributing to BP Alaska the funds necessary to make such payments. BP’s obligations under the Support Agreement are unconditional and directly enforceable by Unit holders.

Neither BP nor BP Alaska may transfer or assign its rights or obligations under the Support Agreement without the prior written consent of the Trustee, except that BP can arrange for its obligations to be performed by any its affiliates so long as BP remains responsible for ensuring that its obligations are performed in a timely manner.

BP Alaska may sell or transfer all or part of its working interest in the Prudhoe Bay Unit, although such a transfer will not relieve BP of its responsibility to ensure that BP Alaska’s payment obligations under the Conveyance are performed.

BP will be released from its obligation under the Support Agreement upon the sale or transfer of all or substantially all of BP Alaska’s working interest in the Prudhoe Bay Unit if the transferee agrees in writing to assume and be bound by BP’s obligation under the Support Agreement. The transferee’s agreement to assume BP’s 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 Moody’s Investors Service, Inc., a rating of at least A- from Standard & Poor’s 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 Alaska’s obligations under the Conveyance and all of BP’s 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 the contiguous Endicott, Lisburne and Pt. McIntyre fields, the Prudhoe Bay Unit was established to optimize field development. Other owners of these fields include affiliates of Exxon Mobil Corporation, ConocoPhillips, ChevronTexaco Corporation and Forest Oil Corporation. The Trust’s Royalty Interest pertains only to production from the Prudhoe Bay field and does not include production from the Endicott, Lisburne and Pt. McIntyre fields.

The operations of BP Alaska and the other working interest owners in the Prudhoe Bay Unit are governed by an agreement dated April 1, 1977 among the State of Alaska and the working interest owners establishing the Prudhoe Bay Unit (the “Prudhoe Bay Unit Agreement”) and an agreement dated April 1, 1977 among the working interest owners governing Prudhoe Bay Unit operations (the “Prudhoe Bay Unit Operating Agreement”).

The Prudhoe Bay Unit Operating Agreement specifies the allocation of production and costs to the working interest owners. It also defines operator responsibilities and voting requirements and is unusual in its establishment of separate participating areas for the gas cap and oil rim. Since July 1, 2000, BP Alaska has been the sole operator of the Prudhoe Bay Unit.

The ownership of the Prudhoe Bay Unit by participating area as of December 31, 2005 is shown in the following table:


	Oil rim			Gas cap
BP Alaska		26.35	%(a)		26.35	%(b)
Exxon Mobil		36.40			36.40
ConocoPhillips		36.07			36.07
Others		1.18			1.18

Total		100.00	%		100.00	%


(a)		The Trust’s share of oil production is computed based on BP Alaska’s ownership interest in the oil rim participating area of 50.68 percent as of February 28, 1989. Subsequent decreases in BP Alaska’s participation in oil rim ownership do not affect calculation of Royalty Production from the BP Working Interests and have not decreased the Trust’s Royalty Interest.

(b)		The Trust’s share of condensate production is computed based on BP Alaska’s ownership interest in the gas cap participating area of 13.84 percent as of February 28, 1989. Subsequent increases in BP Alaska’s gas cap ownership do not affect calculation of Royalty Production from the BP Working Interests and have not increased the Trust’s Royalty Interest.

If BP Alaska fails to pay any costs and expenses chargeable to BP Alaska under the Prudhoe Bay Unit Operating Agreement and the production of oil and condensate is insufficient to pay such costs and expenses, the Royalty Interest is chargeable with a pro rata portion of such costs and expenses and is subject to the enforcement against it of liens granted to the operators of the Prudhoe Bay Unit. However, in the Conveyance BP Alaska agreed to pay all costs and expenses chargeable to it and to ensure that no such costs and expenses will be chargeable against the Royalty Interest. The Trust is not liable for any loss or liability incurred by BP Alaska or others attributable to BP Alaska’s 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 its working interest in the exercise of its reasonable and prudent business judgment without liability to the Trust. BP Alaska also has the right to sell or assign all or any part of its working interest in the Prudhoe Bay Unit, so long as the sale or assignment is expressly made subject to the Royalty Interest and the terms and provisions of the Conveyance.

The Prudhoe Bay Field

The Prudhoe Bay field is located on the North Slope of Alaska, 250 miles north of the Arctic Circle and 650 miles north of Anchorage. The Prudhoe Bay field extends approximately 12 miles by 27 miles and contains nearly 150,000 productive acres. The Prudhoe Bay field, which was discovered in 1968 by BP and others, has been in production since 1977 and is the largest producing oil field in North America. As of December 31, 2005, approximately 10.8 billion barrels of oil and condensate had been produced from the Prudhoe Bay field. Development is well advanced, with approximately $19 billion gross capital spent and a total of about 3,189 wells drilled.

Field Geology

The principal hydrocarbon accumulations at Prudhoe Bay are in the Ivishak sandstone of the Sadlerochit Group at a depth of approximately 8,700 feet below sea level. The Ivishak is overlain by four minor reservoirs of varying extent which are designated the Put River, Eileen, Sag River and Shublik (“PESS”) formations. Underlying the Sadlerochit Group are the oil-bearing Lisburne and Endicott formations. The net production allocated to the Royalty Interest pertains only to the Ivishak and PESS formations, collectively known as the Prudhoe Bay (Permo-Triassic) Reservoir, and does not pertain to the Lisburne and Endicott formations.

The Ivishak sandstone was deposited, commencing some 250 million years ago, during the Permian and Triassic geologic periods. The sediments in the Ivishak are composed of sandstone, conglomerate and shale which were deposited by a massive braided river and delta system that flowed from an ancient mountain system to the north. Oil was trapped in the Ivishak by a combination of structural and stratigraphic trapping mechanisms.

Gross reservoir thickness is 550 feet, with a maximum oil column thickness of 425 feet. The original oil column is bounded on the top by a gas-oil contact, originally at 8,575 feet below sea level across the main field, and on the bottom by an oil-water contact at approximately 9,000 feet below sea level. A layer of heavy oil and tar overlays the oil-water contact in the main field and has an average thickness of around 40 feet.

Oil Characteristics

The oil produced from the Prudhoe Bay (Permo-Triassic) Reservoir is a medium grade, low sulfur crude with an average specific gravity of 27 API degrees. The gas cap composition is such that, upon surfacing, a liquid hydrocarbon phase, known as condensate, is formed.

The Royalty Interest is based upon oil produced from the oil rim and condensate produced from the gas cap, but not upon gas production (which is currently uneconomic) or natural gas liquids production stripped from gas produced.

Historical Production

Production from the Prudhoe Bay field began on June 19, 1977, with the completion of the Trans-Alaska Pipeline System. As of December 31, 2005 there were about 1,111 active producing oil wells, 33 gas reinjection wells, 82 water injection wells and 136 water and miscible gas injection wells in the Prudhoe Bay field. Production from the Prudhoe Bay field has declined over the past five years. The average well production rate was about 546 barrels of oil per day in 2001, 375 barrels per day in 2002, 350 barrels per day in 2003, 317 barrels per day in 2004 and 293 barrels per day in 2005.

BP Alaska’s 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 field’s total production and the net share of oil and condensate (net of State of Alaska royalty) allocated to the BP Working Interests have been as follows during the past five years:


	Oil				Condensate
			Net to BP				Net to BP
Calendar			Working				Working
year	Total field		Interests		Total field		Interests
			(thousand barrels per day)
2001		324.9		144.1		131.2		15.9
2002		293.8		130.3		121.5		14.7
2003		273.2		121.2		113.8		13.8
2004		243.4		107.9		109.0		13.2
2005		228.9		101.5		96.4		11.7

Transportation of Prudhoe Bay Oil

Production from the Prudhoe Bay field is carried to Pump Station 1, the starting point for the Trans-Alaska Pipeline System, through two 34-inch diameter transit lines, one from each half of the Prudhoe Bay field. At Pump Station 1, Alyeska Pipeline Service Company, the pipeline operator, meters the oil and pumps it in the 48-inch diameter pipeline to Valdez, almost 800 miles (1,287 km) to the south, where it is either loaded onto marine tankers or stored temporarily. It takes the oil about seven days to make the trip. The pipeline has a capacity of approximately 1.4 million barrels of oil per day.

Reservoir Management

The Prudhoe Bay field is a complex, combination-drive reservoir, with widely varying reservoir properties. Reservoir management involves directing field activities and projects to maximize the economic value of reserves.

Several different oil recovery mechanisms are currently active in the Prudhoe Bay field, including pressure depletion, gravity drainage/gas cap expansion, water flooding and miscible gas flooding. Separate yet integrated reservoir management strategies have been developed for the areas affected by each of these recovery processes.

Reserve Estimates

The net proved remaining reserves of oil and condensate associated with the BP Working Interests is approximately 1,043 million barrels as of December 31, 2005. This estimate of reserves is based upon various assumptions, including a reasonable estimate of the allocation of hydrocarbon liquids between oil and condensate according to the procedures of the Prudhoe Bay Unit Operating Agreement. Estimates of proved reserves are inherently imprecise and subjective and are revised over time as additional data become available. Such revisions often may be substantial. BP Alaska anticipates that net production from current proved reserves allocated to the BP Working Interests will exceed 90,000 barrels per day until the year 2012. The occurrence of major gas sales could accelerate the time at which BP Alaska’s net production would fall below 90,000 barrels per day, due to the consequent decline in reservoir pressure. BP Alaska projects continued economic production after 2012 at a declining rate until the year 2065; however, for the economic conditions and production forecast as of December 31, 2005, it is estimated that royalty payments will cease following the year 2023.

BP Alaska’s reserve estimates and production assumptions and projections are predicated upon a reasonable estimate of hydrocarbon allocation between oil and condensate. Oil and condensate are physically produced in a commingled stream of hydrocarbon liquids. The allocation of hydrocarbon liquids between the oil and condensate from the Prudhoe Bay field is a theoretical calculation performed in accordance with procedures specified in the Prudhoe Bay Unit Operating Agreement. Due to the differences in percentages between oil and condensate, the overall share of oil and condensate production allocated to the BP Working Interests will vary over time according to the proportions of hydrocarbon liquid being allocated as condensate or as oil. Under the terms of an Issues Resolution Agreement entered into by the Prudhoe Bay Unit owners in October 1990, the allocation procedures have been adjusted to generally allocate condensate in a manner which approximates the anticipated decline in the production of oil until an agreed original condensate reserve of 1,175 million barrels has been allocated to the working interest owners.

The reserves attributable to the Trust’s Royalty Interest constitute only a part of the overall reserves allocated to the BP Working Interests. BP Alaska has estimated that the net remaining proved reserves attributable to the Trust as of December 31, 2005 were 85.3 million barrels of oil and condensate. Using procedures specified in Financial Accounting Standards Board Statement of Financial Standards No. 69, BP Alaska calculated that as of December 31, 2005 production of oil and condensate from the proved reserves allocated to the Trust’s Royalty Interest will result in estimated future net revenues to the Trust of $2,095.2 million, with a present value of $1,209.7 million. BP Alaska’s estimates of proved reserves and the estimated future net revenues from the Prudhoe Bay Unit have been reviewed by Miller and Lents, Ltd., independent oil and gas consultants, as set forth in their report following this section.

There is no precise method of forecasting the allocation of reserve volumes between BP Alaska and the Trust. The Royalty Interest is not a working interest and the Trust is not entitled to receive any specific volume of reserves from the Prudhoe Bay field. Rather, reserve volumes attributable to the Trust at any given date are estimated by allocating to the Trust its share of estimated future production from the Prudhoe Bay field based on WTI Prices and other economic parameters in effect on the date of the evaluation.

The following table shows the net remaining proved reserves of oil and condensate allocated to the BP Working Interests, the net proved reserves allocated to the Trust, and the WTI Prices on the dates indicated:


	Net Proved Reserves
	BP Working				WTI Price
December 31	Interests (a)		Trust (b)		per barrel
	(million barrels)
2001		961.7		43.2	$	19.78
2002		908.7		85.8		31.23
2003		858.7		77.9		32.55
2004		941.4		77.4		43.46
2005		1,043.0		85.3		61.04


(a)		Includes proved undeveloped reserves of 112.5 million barrels at December 31, 2001; 5.5 million barrels at December 31, 2002; 139.9 million barrels at December 31, 2003; 115.4 million barrels at December 31, 2004; and 73.0 million barrels at December 31, 2005.

(b)		Includes proved undeveloped reserves of 0.03 million barrels at December 31, 2002; 11.0 million barrels at December 31, 2003; 9.1 million barrels at December 31, 2004; and 12.3 million barrels at December 31, 2005. No proved undeveloped reserves were attributable to the Trust at December 31, 2001.

The reserve volumes attributable to the Trust are estimated using an allocation of reserve volumes based on estimated future production and the current WTI Price, and assume no future movement in the Consumer Price Index and no future additions of proved reserves by BP Alaska. The estimated reserve volumes attributable to the Trust will vary if different estimates of production, prices and other factors are used. Even if expected reservoir performance does not change, the estimated reserves, economic life, and future revenues attributable to the Trust may change significantly in the future. This may result from changes in the WTI Price or from changes in other prescribed variables utilized in calculations defined by the Overriding Royalty Conveyance. See Note 7 (unaudited) of the Notes to Financial Statements in Item 8.

BP Alaska is under no obligation to make investments in development projects which would add additional non-proved resources to proved reserves and cannot make such investments without the concurrence of the Prudhoe Bay Unit working interest owners. However, several such investments which would augment Prudhoe Bay projects are already in progress. These include additional drilling, water flood expansions and miscible injection continuation/expansion projects. Other possible investments could include expanded gas cycling, miscible/water flood infill drilling, miscible injection supply increases to peripheral areas, heavy oil tar recovery and development of the smaller reservoirs. While there is no assurance that the Prudhoe Bay Unit working interest owners will make any such investments they do regularly assess the technical and economic attractiveness of implementing further projects to increase Prudhoe Bay Unit proved reserves.

In the event of changes in BP Alaska’s current assumptions, oil and condensate recoveries may be reduced from the current estimates, unless recovery projects other than those included in the current estimates are implemented.

INDEPENDENT OIL AND GAS CONSULTANTS’ REPORT

February 6, 2006

The Bank of New York
Trustee, BP Prudhoe Bay Royalty Trust
101 Barclay Street, 8 West
New York, New York 10286


		Re:		Estimates of Proved Reserves,
				Future Production Rates, and
				Future Net Revenues for the
				BP Prudhoe Bay Royalty Trust
				As of December 31, 2005

Gentlemen:

This letter report is a summary of investigations performed in accordance with our engagement by you as described in Section 4.8(d) of the Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc., and The Standard Oil Company. The investigations included reviews of the estimates of Proved Reserves and production rate forecasts of oil and condensate made by BP Exploration (Alaska) Inc. attributable to the BP Prudhoe Bay Royalty Trust as of December 31, 2005. Additionally, we reviewed calculations of the resulting Estimated Future Net Revenues and Present Value of Estimated Future Net Revenues attributable to the BP Prudhoe Bay Royalty Trust.

The estimates and calculations reviewed are summarized in the report prepared by BP Exploration (Alaska) Inc. and transmitted with a cover letter dated February 3, 2006 addressed to Mr. Remo J. Reale of The Bank of New York and signed by Ms. Maureen Johnson. Reviews were also performed by Miller and Lents, Ltd. during this year or in previous years of (1) the procedures for estimating and documenting Proved Reserves, (2) the estimates of in-place reservoir volumes, (3) the estimates of recovery factors and production profiles for the various areas, pay zones, projects, and recovery processes that are included in the estimate of Proved Reserves, (4) the production strategy and procedures for implementing that strategy, (5) the sufficiency of the data available for making estimates of Proved Reserves and production profiles, and (6) pertinent provisions of the Prudhoe Bay Unit Operating Agreement, the Issues Resolution Agreement, the Overriding Royalty Conveyance, the Trust Conveyance, the BP Prudhoe Bay Royalty Trust Agreement, and other related documents referenced in the Form F-3 Registration Statement filed with the Securities and Exchange Commission on August 7, 1989, by BP Exploration (Alaska) Inc.

Miller and Lents, Ltd.


The Bank of New York		February 6, 2006
Trustee, BP Prudhoe Bay Royalty Trust

Proved Reserves were estimated by BP Exploration (Alaska) Inc. in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a). Estimated Future Net Revenues and Present Value of Estimated Future Net Revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

The Prudhoe Bay (Permo-Triassic) Reservoir is defined in the Prudhoe Bay Unit Operating Agreement. The Prudhoe Bay Unit is an oil and gas unit situated on the North Slope of Alaska. The BP Prudhoe Bay Royalty Trust is entitled to a royalty payment on 16.4246 percent of the first 90,000 barrels of the actual average daily net production of oil and condensate for each calendar quarter from the BP Exploration (Alaska) Inc. working interest as defined in the Overriding Royalty Conveyance. The payment amount depends upon the Per Barrel Royalty which in turn depends upon the West Texas Intermediate Price, the Chargeable Costs, the Cost Adjustment Factor, and Production Taxes, all of which are defined in the Overriding Royalty Conveyance. “Barrel” as used herein means Stock Tank Barrel as defined in the Overriding Royalty Conveyance.

Our reviews do not constitute independent estimates of the reserves and annual production rate forecasts for the areas, pay zones, projects, and recovery processes examined. We relied upon the accuracy and completeness of information provided by BP Exploration (Alaska) Inc. with respect to pertinent ownership interests and various other historical, accounting, engineering, and geological data.

As a result of our cumulative reviews, based on the foregoing, we conclude that:

	1.		A large body of basic data and detailed analyses are available and were used in making the estimates. In our judgment, the quantity and quality of currently available data on reservoir boundaries, original fluid contacts, and reservoir rock and fluid properties are sufficient to indicate that any future revisions to the estimates of total original in-place volumes should be minor. Furthermore, the data and analyses on recovery factors and future production rates are sufficient to support the Proved Reserves estimates.

	2.		The methods and procedures employed to accumulate and evaluate the necessary information and to estimate, document, and reconcile reserves, annual production rate forecasts, and future net revenues are effective and are in accordance with generally accepted geological and engineering practice in the petroleum industry.

	3.		Based on our limited independent tests of the computations of reserves, production flowstreams, and future net revenues, such computations were performed in accordance with the methods and procedures described to us.

	4.		The estimated net remaining Proved Reserves attributable to the BP Prudhoe Bay Royalty Trust as of December 31, 2005, of 85.31 million barrels of oil and condensate are, in the aggregate, reasonable. Of the 85.31 million barrels of total Proved Reserves, 73.03 million barrels are Proved Developed Reserves, and 12.28 million barrels are Proved Undeveloped Reserves.

	5.		Utilizing the specified procedures outlined in Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69, BP Exploration (Alaska) Inc. calculated that as of December 31, 2005 production of the Proved Reserves will result in

Miller and Lents, Ltd.


The Bank of New York		February 6, 2006
Trustee, BP Prudhoe Bay Royalty Trust

			Estimated Future Net Revenues of $2,095.2 million and Present Value of Estimated Future Net Revenues of $1,209.7 million to the BP Prudhoe Bay Royalty Trust. These estimates are reasonable.

	6.		BP Exploration (Alaska) Inc. estimated that as of December 31, 2005, 1,085.0 million barrels of Proved Reserves have been added to Current Reserves. This estimate is reasonable. Current Reserves are defined in the Overriding Royalty Conveyance as net Proved Reserves of 2,035.6 million barrels as of December 31, 1987. Net additions to Proved Reserves after December 31, 1987 affect the Chargeable Costs that are used to calculate the Per Barrel Royalty paid to the BP Prudhoe Bay Royalty Trust.

	7.		The BP Exploration (Alaska) Inc. projection that its net production of oil and condensate from Proved Reserves will continue at an average rate exceeding 90,000 barrels per day until the year 2012 is reasonable. As long as the Per Barrel Royalty has a positive value, average daily production attributable to the BP Prudhoe Bay Royalty Trust will remain constant until the net production falls below 90,000 barrels per day; thereafter, production attributable to the BP Prudhoe Bay Royalty Trust will decline with the BP Exploration (Alaska) Inc. production. However, the Per Barrel Royalty will not have a positive value if the West Texas Intermediate Price is less than the sum of the per barrel Chargeable Costs and per barrel Production Taxes, appropriately adjusted in accordance with the Overriding Royalty Conveyance. Under such circumstances, average daily production attributable to the BP Prudhoe Bay Royalty Trust will have no value and therefore will not contribute to the reserves regardless of BP Exploration (Alaska) Inc.’s net production level.

	8.		Based on the West Texas Intermediate Price of $61.04 per barrel on December 31, 2005, current Production Taxes, and the Chargeable Costs adjusted as prescribed by the Overriding Royalty Conveyance, the projection that royalty payments will continue through the year 2023 is reasonable. BP Exploration (Alaska) Inc. expects continued economic production at a declining rate through the year 2065; however, for the economic conditions and production forecast as of December 31, 2005 the Per Barrel Royalty will be zero following the year 2023. Therefore, no reserves are currently attributed to the BP Prudhoe Bay Royalty Trust after that date.

	9.		Even if expected reservoir performance does not change, the estimated reserves, economic life, and future revenues attributable to the BP Prudhoe Bay Royalty Trust may change significantly in the future. This may result from changes in the West Texas Intermediate Price or from changes in other prescribed variables utilized in calculations defined by the Overriding Royalty Conveyance.

Estimates of ultimate and remaining reserves and production scheduling depend upon assumptions regarding expansion or implementation of alternative projects or development programs and upon strategies for production optimization. BP Exploration (Alaska) Inc. has continual reservoir management, surveillance, and planning efforts dedicated to (1) gathering new information, (2) improving the accuracy of its reserves and production capacity estimates, (3) recognizing and exploiting new opportunities, (4) anticipating potential problems and taking corrective actions, and (5) identifying, selecting, and implementing optimum recovery program and cost reduction alternatives. Given this

Miller and Lents, Ltd.


The Bank of New York		February 6, 2006
Trustee, BP Prudhoe Bay Royalty Trust

significant effort and ever-changing economic conditions, estimates of reserves and production profiles will change periodically.

The current estimate of Proved Reserves includes only those projects or development programs that are deemed reasonably certain to be implemented, given current economic and regulatory conditions. Future projects, development programs, or operating strategies different from those assumed in the current estimates may change future estimates and affect recoveries. However, because several complementary and alternative projects are being considered for recovery of the remaining oil in the reservoir, a decision not to implement a currently planned project may allow scope expansion or implementation of another project, thereby increasing the overall likelihood of recovering the reserves.

Future production rates will be controlled by facilities limitations and upsets, well downtime, and the effectiveness of programs to optimize production and costs. BP Exploration (Alaska) Inc. currently expects continued economic production from the reservoir at a declining rate through the year 2065. Additional drilling, workovers, facilities modifications, new recovery projects, and programs for production enhancement and optimization are expected to mitigate but not eliminate the decline in gross oil and condensate production capacity.

In making its future production rate forecasts, BP Exploration (Alaska) Inc. provided for normal downtime and planned facilities upsets. Although allowances for unplanned upsets are also considered in the estimates, the studies do not provide for any impediments to crude oil production as a consequence of major disruptions.

Under current economic conditions, gas from the Alaskan North Slope, except for minor volumes, cannot be marketed commercially. Oil and condensate recoveries are expected to be greater as a result of continued reinjection of produced gas than the recoveries would be if major volumes of produced gas were being sold. No major gas sale is assumed in the current estimates. If major gas sales are undertaken in the future, BP Exploration (Alaska) Inc. estimates that such sales would not actually commence until eight to ten years in the future. In the event that major gas sales are initiated, ultimate oil and condensate recoveries may be reduced from the current estimates unless recovery projects other than those included in the current estimates are implemented.

Large volumes of natural gas liquids are likely to be produced and marketed in the future whether or not major gas sales become viable. Natural gas liquids reserves are not included in the estimates cited herein. The BP Prudhoe Bay Royalty Trust is not entitled to royalty payments from production or sales of natural gas or natural gas liquids.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those reflected in this study or disruption of existing transportation routes or facilities may cause the total quantity of oil or condensate to be recovered, actual production rates, prices received, or operating and capital costs to vary from those reviewed in this report.

Miller and Lents, Ltd., is an independent oil and gas consulting firm. None of the principals of this firm have any direct financial interests in BP Exploration (Alaska) Inc. or its parent or any related

Miller and Lents, Ltd.


The Bank of New York		February 6, 2006
Trustee, BP Prudhoe Bay Royalty Trust

companies or in the BP Prudhoe Bay Royalty Trust. Our fee is not contingent upon the results of our work or report, and we have not performed other services for BP Exploration (Alaska) Inc. or the BP Prudhoe Bay Royalty Trust that would affect our objectivity.


Very truly yours,

MILLER AND LENTS, LTD.

By	/s/ William P. Koza, P.E. William P. Koza, P.E.	[SEAL]
	Vice President

WPK/hsd

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 Alaska’s oil and gas activities are subject to existing federal, state and local laws and regulations relating to health, safety, environmental quality and pollution control. BP Alaska believes that the equipment and facilities currently being used in its operations generally comply with the applicable legislation and regulations. During the past few years, numerous environmental laws and regulations have taken effect at the federal, state and local levels. Oil and gas operations are subject to extensive federal and state regulation and to interruption or termination by governmental authorities due to ecological and other considerations and in certain circumstances impose absolute liability upon lessees for the cost of cleaning up pollutants and for pollution damages resulting from their operations. Although BP Alaska has advised that the existence of legislation and regulation has had no material adverse effect on BP Alaska’s current method of operations, existing and future legislation and regulations cannot be predicted.

CERTAIN TAX CONSIDERATIONS

The following is a summary of the principal tax consequences to Unit holders resulting from the ownership and disposition of Units. The laws and regulations affecting these matters are complex, and are subject to change by future legislation or regulations or new interpretations by the Internal Revenue Service, state taxing authorities or the courts. In addition, there may be differences of opinion as to the applicability or interpretation of present tax laws and regulations. BP Alaska and the Trust have not requested any rulings from the Internal Revenue Service with respect to the tax treatment of the Units, and no assurance can be given that the Internal Revenue Service would concur with the statements below.

Unit holders are urged to consult their tax advisors regarding the effects on their specific tax situations of owning and disposing of Units.

Federal Income Tax

Classification of the Trust

The following discussion assumes that the Trust is properly classified as a grantor trust under current law and is not an association taxable as a corporation.

General Features of Grantor Trust Taxation

A grantor trust is not subject to tax, and its beneficiaries (the Unit holders in the case of the Trust) are considered for tax purposes to own the assets of the trust directly. The Trust pays no federal income tax but files an information return reporting all items of income or deduction. If a court were to hold that the Trust is an association taxable as a corporation, the Trust would incur substantial income tax liabilities in addition to its other expenses.

Taxation of Unit Holders

In computing his federal income tax liability, each Unit holder is required to take into account his share of all items of Trust income, gain, loss, deduction, credit and tax preference, based on the Unit holder’s method of accounting. Consequently, it is possible that in any year a Unit holder’s share of the

taxable income of the Trust may exceed the cash actually distributed to him in that year. For example, if the Trustee should add to the reserve for the payment of Trust liabilities or repay money borrowed to satisfy debts of the Trust, the money used to replenish the reserve or to repay the loan is income to and must be reported by the Unit holder, even though the money was not distributed to the Unit holder.

The Trust makes quarterly distributions to the persons who held Units of record on each Quarterly Record Date. The terms of the Trust Agreement seek to assure to the extent practicable that income, expenses and deductions attributable to each distribution are reportable by the Unit holder who receives the distribution.

The Trust allocates income and deductions to Unit holders based on record ownership at Quarterly Record Dates. It is not known whether the Internal Revenue Service will accept the allocation based on this method.

Depletion Deductions

The owner of an economic interest in producing oil and gas properties is entitled to deduct an allowance for the greater of cost depletion or (if otherwise allowable) percentage depletion on each such property. A Unit holder’s deduction for cost depletion in any year is calculated by multiplying the holder’s adjusted tax basis in his Units (generally his cost less prior depletion deductions) by Royalty Production during the year and dividing that product by the sum of Royalty Production during the year and estimated remaining Royalty Production as of the end of the year. The allowance for percentage depletion generally does not apply to interests in proven oil and gas properties that were transferred after December 31, 1974 and prior to October 12, 1990. The Omnibus Budget Reconciliation Act of 1990 repealed this rule for transfers occurring on or after October 12, 1990. Unit holders who acquired their Units on or after that date may be permitted to deduct an allowance for percentage depletion if such deduction would otherwise exceed the allowable deduction for cost depletion. In order to take percentage depletion, a Unit holder must qualify for the “independent producer” exemption contained in section 613A(c) of the Internal Revenue Code of 1986. Percentage depletion is based on the Unit holder’s gross income from the Trust rather than on his adjusted basis in his Units. Any deduction for cost depletion or percentage depletion allowable to a Unit holder reduces his adjusted basis in his Units for purposes of computing subsequent depletion or gain or loss on any subsequent disposition of Units.

Unit holders must maintain records of their adjusted basis in their Units, make adjustments for depletion deductions to such basis, and use the adjusted basis for the computation of gain or loss on the disposition of the Units.

Taxation of Foreign Unit Holders

Generally, a holder of Units who is a nonresident alien individual or which is a foreign corporation (a “Foreign Taxpayer”) is subject to tax on the gross income produced by the Royalty Interest at a rate equal to 30 percent (or at a lower treaty rate, if applicable). This tax is withheld by the Trustee and remitted directly to the United States Treasury. A Foreign Taxpayer may elect to treat the income from the Royalty Interest as effectively connected with the conduct of a United States trade or business under Internal Revenue Code section 871 or section 882, or pursuant to any similar provisions of applicable treaties. If a Foreign Taxpayer makes this election, it is entitled to claim all deductions with respect to such income, but a United States federal income tax return must be filed to claim such deductions. This election once made is irrevocable unless an applicable treaty provides otherwise or unless the Secretary of the Treasury consents to a revocation.

Section 897 of the Internal Revenue Code and the Treasury Regulations thereunder treat the Trust as if it were a United States real property holding corporation. Foreign holders owning more than

five percent of the outstanding Units are subject to United States federal income tax on the gain on the disposition of their Units. Foreign Unit holders owning less than five percent of the outstanding Units are not subject to United States federal income tax on the gain on the disposition of their Units, unless they have elected under Internal Revenue Code section 871 or section 882 to treat the income from the Royalty Interest as effectively connected with the conduct of a United States trade or business.

If a Foreign person is a corporation which made an election under Internal Revenue Code section 882(d), the corporation would also be subject to a 30 percent tax under Internal Revenue Code section 884. This tax is imposed on U.S. branch profits of a foreign corporation that are not reinvested in the U.S. trade or business. This tax is in addition to the tax on effectively connected income. The branch profits tax may be either reduced or eliminated by treaty.

Sale of Units

Generally, a Unit holder will realize gain or loss on the sale or exchange of his Units measured by the difference between the amount realized on the sale or exchange and his adjusted basis for such Units. Gain on the sale of Units by a holder that is not a dealer with respect to such Units will generally be treated as capital gain. However, pursuant to Internal Revenue Code section 1254, certain depletion deductions claimed with respect to the Units must be recaptured as ordinary income upon sale or disposition of such interest.

Backup Withholding

A payor must withhold 28 percent of any reportable payment if the payee fails to furnish his taxpayer identification number (“TIN”) to the payor in the required manner or if the Secretary of the Treasury notifies the payor that the TIN furnished by the payee is incorrect. Unit holders will avoid backup withholding by furnishing their correct TINs to the Trustee in the form required by law.

State Income Taxes

Unit holders may be required to report their share of income from the Trust to their state of residence or commercial domicile. However, only corporate Unit holders will need to report their share of income to the State of Alaska. Alaska does not impose an income tax on individuals or estates and trusts. All Trust income is Alaska source income to corporate Unit holders and should be reported accordingly.

ITEM 2. PROPERTIES

Reference is made to Item 1 for the information required by this item.

ITEM 1A. RISK FACTORS

Owners of Units are exposed to risk and uncertainties that are particular to their investment. This Item describes several, but not necessarily all of them.

•

Royalty Production from the Prudhoe Bay field is projected to decline after 2012 and will eventually cease.

The Prudhoe Bay field has been in production since 1977. Development of the field is largely completed, and proved reserves are being depleted. Production of oil and condensate from the field has been declining during recent years and the decline is expected to continue. BP Alaska has estimated that net production from current proved reserves allocated to the BP Working Interests will exceed 90,000 barrels per day until the year 2012. Economic production is expected to continue after 2012, but at a rate less than 90,000 barrels per day and royalty payments to the Trust are projected to cease after 2023. The foregoing estimates are based on economic conditions and production forecasts as of the end of 2005,

and also depend on various assumptions, projections and estimates which are continually revised and updated by BP Alaska. These revisions could result in material changes to the projected declines in production. It is possible that economic production from the reserves allocated to the BP Working Interests could decline more quickly and end sooner that is currently projected, especially if natural gas production from the Prudhoe Bay field commences, as discussed in the following paragraphs.

•

Construction of a proposed gas pipeline from the North Slope of Alaska to the Midwestern United States could accelerate the decline in net royalty production from the Prudhoe Bay field, result in higher production tax deductions from royalty payments to the Trust, or both.

On February 21, 2006 Alaska Governor Frank Murkowski announced that the State and BP Alaska, ConocoPhilips and Exxon Mobil had reached agreement in principle on a natural gas pipeline contract. The proposed $20 billion natural gas pipeline would run from Alaska’s North Slope through Canada and into the Midwestern United States and would be completed in six to eight years. The Governor also announced that he had proposed legislation to reform Alaska’s oil production tax. The new petroleum production tax would replace the current production tax on oil, which is based on a percentage of the gross value of production. Under the Governor’s petroleum production tax, producers will pay a 20 percent tax rate on net profits and will receive a 20 percent tradable capital investment tax credit and a $73 million standard deduction.

The gas pipeline contract has not been made public and is not final. The Governor’s production tax bill has been introduced in both houses of the Alaska Legislature (as SB 305 in the Senate and as HB 488 in the House), but has not been enacted and may be amended in committee. There could be significant changes to the pipeline contract and to the petroleum production tax proposed by the Governor.

At present, extraction of natural gas from the Prudhoe Bay Unit is not economical. Natural gas released by pumping oil is reinjected into the ground, which helps to maintain reservoir pressure and facilitates extraction of oil from the fields. If the proposed natural gas pipeline is constructed, it will make it economical to extract natural gas from the Prudhoe Bay Unit and transport it to the lower 48 states for sale. Extraction of natural gas from the Prudhoe Bay field will lower reservoir pressure. The lowering of the reservoir pressure may accelerate the decline in production from the BP Working Interests and the time at which royalty payments to the Trust will cease. Since the Trust is not entitled to any royalty payments with respect to natural gas production from the BP Working Interests, the Unit holders will not realize any offsetting benefit from the natural gas production.

It is too early to tell what effect the Governor’s tax proposal, if enacted, will have on the Production Taxes chargeable against Royalty Production under the Conveyance. The Per Barrel Royalty payable to the Trust could be reduced if the new petroleum production tax results in an effective rate of tax chargeable against the Royalty Interest that is higher than the current 15 percent tax imposed on wellhead value.

•

Royalty payments by BP Alaska to the Trust are unpredictable, because they depend directly on world crude oil prices which have been volatile in recent years.

During the past decade, crude oil prices have been very volatile. Crude oil prices have increased continuously since 2001, with the average WTI Price having reached $63 per barrel during the third quarter of 2005. Before 2002, though, crude oil prices went through a period of extreme volatility. In late 1998 and early 1999, spot oil prices fell to a historic lows, reaching barely $10 per barrel in December 1998. As a result, the average WTI Price during the fourth quarter of 1998 and the first quarter of 1999 fell below the total adjusted Chargeable Costs and Production Taxes chargeable against Royalty

Production and the Trust did not receive royalty distributions from BP Alaska during the first two quarters of 1999.

Recent moves in crude oil prices have been affected by many factors, including changes in demand by oil-consuming countries, the actions of OPEC to control production by members of the cartel, shifts in inventory management strategies by international oil companies, increasing effects of the oil futures market, and other unpredictable political, psychological and economic factors such as the war in Iraq and tensions with Iran over its nuclear program. Future domestic and international events and conditions may produce wide swings in crude oil prices over relatively short periods of time. Unit holders thus are subject to the risk that cash distributions with respect to their Units may vary widely from quarter to quarter.

•

Production from the Prudhoe Bay field could be interrupted by damage to the Trans-Alaska Pipeline System from natural disasters, accidents, or deliberate attacks.

The Trans-Alaska Pipeline System connects the North Slope oil fields to the southern port of Valdez, almost 800 miles away. It is the only way that oil can be transported from the North Slope to market. The pipeline system crosses three mountain ranges, many rivers and streams and thaw-sensitive permafrost. It is susceptible along its length to damage from earthquakes, forest fires and other natural disasters. The pipeline system also is vulnerable to accidental damage and deliberate attacks. If the pipeline or its pumping stations should suffer major damage from natural or man-made causes, production from the Prudhoe Bay field could be shut in until the pipeline system can be repaired and restarted. Royalty payments to the Trust could be reduced by a material amount as a result of interruption to production from the Prudhoe Bay field.

•

Production from the Prudhoe Bay Unit may be interrupted or discontinued by BP Alaska.

BP Alaska has no obligation to continue production from the Prudhoe Bay Unit or to maintain production at any level and may interrupt or discontinue production at any time. The Trust does not have the right to take over operation of the BP Working Interests or share in any operating decisions by BP Alaska concerning the Prudhoe Bay Unit. The operation of the Prudhoe Bay Unit is subject to normal operating hazards incident to the production and transportation of oil in Alaska. In the event of damage to the Prudhoe Bay Unit which is covered by insurance, BP Alaska has no obligation to use insurance proceeds to repair such damage and may elect to retain such proceeds and close damaged areas to production.

•

There are potential conflicts of interest between BP Alaska and the Trust that could affect the royalties paid to Unit holders.

The interests of BP Alaska and the Trust with respect to the Prudhoe Bay Unit could at times be different. The Per Barrel Royalty that BP Alaska pays to the Trust is based on the WTI Price and Chargeable Costs, both of which are amounts contractually defined the Conveyance. The WTI Price does not necessarily correspond to the actual price realized by BP Alaska for crude oil produced from the BP Working Interests, and Chargeable Costs may not bear any relation to BP Alaska’s actual costs of production. The actual per barrel profit realized by BP Alaska on the Royalty Production may differ materially from the Per Barrel Royalty that it is required to pay to the Trust. It is possible under certain circumstances that the relationship between BP Alaska’s actual per barrel revenues and costs could be such that BP Alaska might determine to interrupt or discontinue production in whole or in part from the BP Working Interests even though a Per Barrel Royalty might otherwise be payable to the Trust under the Conveyance.

ITEM 1B. UNRESOLVED STAFF COMMENTS

The Trust has not received any written comments from the staff of the Securities and Exchange Commission regarding its periodic or current reports under the Exchange Act that remain unresolved.

ITEM 3. LEGAL PROCEEDINGS

There are no pending legal proceedings to which the Trust is a party or of which any of its property is the subject.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of Unit holders during the fourth quarter ended December 31, 2005.

PART II

ITEM 5. MARKET FOR REGISTRANT’S UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS

The Units are listed and traded on the New York Stock Exchange under the symbol BPT. The following table shows the high and low sales prices per Unit on the New York Stock Exchange and the cash distributions paid per Unit, for each calendar quarter in the two years ended December 31, 2005.


					Distributions
	High		Low		Per Unit
2004:
First Quarter	$	30.25	$	22.50	$	0.670
Second Quarter		32.90		26.31		0.846
Third Quarter		40.00		32.13		0.998
Fourth Quarter		50.50		39.95		1.304

2005:
First Quarter	$	70.95	$	46.40	$	1.544
Second Quarter		75.79		56.47		1.545
Third Quarter		79.99		69.50		1.728
Fourth Quarter		79.90		60.10		2.282

As of March 10, 2006, 21,400,000 Units were outstanding and were held by 753 holders of record. No Units were purchased by the Trust or any affiliated purchaser during the year ended December 31, 2005.

Future payments of cash distributions are dependent on such factors as the prevailing WTI Price, the relationship of the rate of change in the WTI Price to the rate of change in the Consumer Price Index, the Chargeable Costs, the rates of Production Taxes prevailing from time to time, and the actual production from the BP Working Interests. See “THE ROYALTY INTEREST” in Item 1.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents in summary form selected financial information regarding the Trust.


	Year ended December 31
	2005		2004		2003		2002		2001
	(in thousands, except per Unit amounts)
Royalty revenues	$	152,978		82,682		55,986		33,061		59,934
Interest income	$	37		11		10		23		70
Trust administration expenses	$	1,097		976		1,168		822		724
Cash earnings	$	151,918		81,717		54,828		32,262		59,280
Cash distributions	$	151,908		81,702		54,867		32,246		59,319
Cash distributions per unit	$	7.098		3.818		2.564		1.507		2.772


	December 31
	2005		2004		2003		2002		2001
	(dollar amounts in thousands)
Trust Corpus	$	10,876		12,881		14,730		16,498		18,564
Total Assets	$	11,054		13,052		15,046		17,093		19,086
Units outstanding		21,400,000		21,400,000		21,400,000		21,400,000		21,400,000

ITEM 7. TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Liquidity and Capital Resources

The Trust is a passive entity. The Trustee’s activities are limited to collecting and distributing the revenues from the Royalty Interest and paying liabilities and expenses of the Trust. Generally, the Trust has no source of liquidity and no capital resources other than the revenue attributable to the Royalty Interest that it receives from time to time. See the discussion under “THE ROYALTY INTEREST” in Item 1 for a description of the calculation of the Per Barrel Royalty, and the discussion under “THE PRUDHOE BAY UNIT AND FIELD – Reserve Estimates” and “INDEPENDENT OIL AND GAS CONSULTANTS’ REPORT” in Item 1 for information concerning the estimated future net revenues of the Trust. However, the Trust Agreement gives the Trustee power to borrow, establish a cash reserve, or dispose of all or part of the Trust property under limited circumstances. See the discussion under “BUSINESS – The Trust” in Item 1.

In 1999, due to declines in oil prices during the fourth quarter of 1998 and the first quarter of 1999 which resulted in the Trust not receiving cash distributions for two quarters, the Trustee established a $1,000,000 cash reserve to provide liquidity to the Trust during any future periods in which the Trust does not receive a distribution. The Trustee will draw funds from the cash reserve account during any quarter in which the quarterly distribution received by the Trust does not exceed the liabilities and expenses of the Trust, and will replenish the reserve from future quarterly distributions, if any. The Trustee anticipates that it will keep this cash reserve program in place until termination of the Trust.

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 Trust’s 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 Alaska’s operations during the twelve-month period ended on the preceding September 30.

As long as BP Alaska’s average daily net production from the BP Working Interests exceeds 90,000 barrels, which BP Alaska currently projects will continue until the year 2012, the only factors affecting the Trust’s revenues and distributions to Unit holders are changes in WTI Prices, scheduled annual increases in Chargeable Costs, changes in the Consumer Price Index, changes in Production Taxes, changes in the expenses of the Trust, contributions to the cash reserve and interest earned on the cash reserve.

During the years 2004 and 2005 and the period of 2006 up to the date of this report, WTI Prices have been above the level necessary for the Trust to receive a Per Barrel Royalty. Whether the Trust will be entitled to future distributions during the remainder of 2006 will depend on WTI Prices prevailing during the remainder of the year.

2005 compared to 2004

Continued increases in world oil prices drove higher WTI Prices in the fourth quarter of 2004 and the first three quarters of 2005 (the period on which calendar 2005 cash basis revenues were based), which averaged 44% higher during that period than during the twelve months ended September 30, 2004. As a result, royalty revenues during 2005 rose approximately 85% from 2004, and cash distributions rose approximately 86%. Chargeable Costs per barrel increased from $12.00 to $12.25, beginning in the first quarter of 2005. The increase in Chargeable Costs, continued increases in the Cost Adjustment Factor (which produced adjusted Chargeable Costs averaging $18.15 per barrel during the twelve months ended September 30, 2005) and increases in Production Taxes (which averaged approximately 52.5% higher during the twelve months ended September 30, 2005 than in the prior twelve-month period) attenuated the effect of the increase in WTI Prices on the Trust’s revenues in 2005.

2004 compared to 2003

Increases in world oil prices drove higher WTI Prices in the fourth quarter of 2003 and the first three quarters of 2004 (the period on which calendar 2004 cash basis revenues were based), which averaged 22% higher during that period than during the twelve months ended September 30, 2003. As a result, royalty revenues during 2004 rose approximately 48% from 2003, and cash distributions rose

approximately 49%. Chargeable Costs per barrel increased from $11.75 to $12.00, beginning in the first quarter of 2004. The increase in Chargeable Costs, increases in the Cost Adjustment Factor (which produced adjusted Chargeable Costs averaging $17.22 per barrel during the twelve months ended September 30, 2004) and increases in Production Taxes (which averaged approximately 27% higher during the twelve months ended September 30, 2004 than in the prior twelve-month period) attenuated the effect of the increase in WTI Prices on the Trust’s revenues in 2004.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Trust is a passive entity and except for the Trust’s 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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

BP PRUDHOE BAY ROYALTY TRUST

Index To Financial Statements


	Page
Report of Independent Registered Public Accounting Firm		31

Statements of Assets, Liabilities and Trust Corpus as of December 31, 2005 and 2004		32

Statements of Cash Earnings and Distributions for the years ended December 31, 2005, 2004 and 2003		33

Statements of Changes in Trust Corpus for the years ended December 31 2005, 2004 and 2003		34

Notes to Financial Statements		35

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Trustee and Holders of Trust Units of BP Prudhoe Bay Royalty Trust:

We have audited the accompanying statements of assets, liabilities and trust corpus of BP Prudhoe Bay Royalty Trust (the “Trust”) as of December 31, 2005 and 2004, and the related statements of cash earnings and distributions and changes in trust corpus for each of the years in the three-year period ended December 31, 2005. These financial statements are the responsibility of The Bank of New York, as the Trust’s trustee (the “Trustee”). Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the trustee, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust as of December 31, 2005 and 2004 and its cash earnings and distributions and changes in trust corpus for each of the years in the three-year period ended December 31, 2005 in conformity with the modified cash basis of accounting described in Note 2.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005, 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 15, 2006 expressed an unqualified opinion on the trustee’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Dallas, Texas

March 15, 2006

BP Prudhoe Bay Royalty Trust

Statement of Assets, Liabilities and Trust Corpus

(Prepared on a modified basis of cash receipts and disbursements)

(In thousands, except unit data)


	December 31,		December 31,
	2005		2004
Assets

Royalty Interest, net (Notes 1, 2 and 3)	$	10,043	$	12,051
Cash and cash equivalents (Note 2)		1,011		1,001


Total Assets	$	11,054	$	13,052


Liabilities and Trust Corpus

Accrued expenses	$	178	$	171

Trust Corpus (40,000,000 units of beneficial interest authorized, 21,400,000 units issued and outstanding		10,876		12,881


Total Liabilities and Trust Corpus	$	11,054	$	13,052

See accompanying notes to financial statements.

BP Prudhoe Bay Royalty Trust

Statements of Cash Earnings and Distributions

(Prepared on a modified basis of cash receipts and disbursements)

(In thousands, except unit data)


	December 31,
	2005			2004			2003
Royalty revenues	$	152,978		$	82,682		$	55,986
Interest income		37			11			10

Less: Trust administrative expenses		(1,097	)		(976	)		(1,168	)


Cash earnings	$	151,918		$	81,717		$	54,828


Cash distributions	$	151,908		$	81,702		$	54,867


Cash distributions per unit	$	7.098		$	3.818		$	2.564


Units outstanding		21,400,000			21,400,000			21,400,000

See accompanying notes to financial statements.

BP Prudhoe Bay Royalty Trust

Statements of Changes in Trust Corpus

(Prepared on a modified basis of cash receipts and disbursements)

(In thousands)


	December 31,
	2005			2004			2003
Trust Corpus at beginning of year	$	12,881		$	14,730		$	16,498
Cash earnings		151,918			81,717			54,828
Decrease (increase) in accrued expenses		(7	)		145			279
Cash distributions		(151,908	)		(81,702	)		(54,867	)
Amortization of Royalty Interest		(2,008	)		(2,009	)		(2,008	)


Trust Corpus at end of year	$	10,876		$	12,881		$	14,730

See accompanying notes to financial statements.

BP Prudhoe Bay Royalty Trust

Notes to Financial Statements

(Prepared on a modified basis of cash receipts and disbursements)

December 31, 2005

(1)		Formation of the Trust and Organization

		BP Prudhoe Bay Royalty Trust (the “Trust”), a grantor trust, was created as a Delaware business trust pursuant to a Trust Agreement dated February 28, 1989 among the Standard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”), The Bank of New York (The “Trustee”) and The Bank of New York (Delaware), as co-trustee. Standard Oil and BP Alaska are indirect wholly owned subsidiaries of the BP p.l.c. (“BP”).

		On February 28, 1989, Standard Oil conveyed an overriding royalty interest (the “Royalty Interest”) to the Trust. The Trust was formed for the sole purpose of owning and administering the Royalty Interest. The Royalty Interest represents the right to receive, effective February 28, 1989, a per barrel royalty (the “Per Barrel Royalty”) of 16.4246% on the lesser of (a) the first 90,000 barrels of the average actual daily net production of oil and condensate per quarter or (b) the average actual daily net production of oil and condensate per quarter from BP Alaska’s working interest as of February 28, 1989 in the Prudhoe Bay Field (the “Field”), located on the North Slope of Alaska. Trust Unit holders will remain subject at all times to the risk that production will be interrupted or discontinued or fall, on average, below 90,000 barrels per day in any quarter. BP has guaranteed the performance of BP Alaska of its payment obligations with respect to the Royalty Interest.

		Effective January 1, 2000, BP Alaska and all other Prudhoe Bay working interest owners cross-assigned interests in the Prudhoe Bay Field pursuant to the Prudhoe Bay Unit Alignment Agreement. BP Alaska retained all rights, obligations, and liabilities associated with the Trust.

		The trustees of the Trust are The Bank of New York, a New York corporation authorized to do a banking business, and The Bank of New York (Delaware), a Delaware banking corporation. The Bank of New York (Delaware) serves as co-trustee in order to satisfy certain requirements of the Delaware Trust Act. The Bank of New York alone is able to exercise the rights and powers granted to the Trustee in the Trust Agreement.

		The Per Barrel Royalty in effect for any day is equal to the price of West Texas Intermediate crude oil (the “WTI Price”) for that day less scheduled Chargeable Costs (adjusted in certain situations for inflation) and Production Taxes (based on statutory rates then in existence).

		The Trust is passive, with the Trustee having only such powers as are necessary for the collection and distribution of revenues, the payment of Trust liabilities, and the protection of the Royalty Interest. The Trustee, subject to certain conditions, is obligated to establish cash reserves and borrow funds to pay liabilities of the Trust when they become due. The Trustee may sell Trust properties only (a) as authorized by a vote of the Trust Unit Holders, (b) when necessary to provide for the payment of specific liabilities of the Trust then due (subject to certain conditions) or (c) upon termination of the Trust. Each Trust Unit issued and outstanding represents an equal undivided share of beneficial interest in the Trust. Royalty payments are received by the Trust and distributed to Trust Unit holders, net of Trust expenses, in the month succeeding the end of each calendar quarter. The Trust will terminate upon the first to occur of the following events:

On or prior to December 31, 2010: upon a vote of Trust Unit Holders of not less than 70% of the outstanding Trust Units.

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005

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 year’s 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 Trust’s assets, liabilities, Corpus, earnings, and distributions, as follows:

	a.		Revenues are recorded when received (generally within 15 days of the end of the preceding quarter) and distributions to Trust Unit Holders are recorded when paid.

	b.		Trust expenses (which include accounting, engineering, legal, and other professional fees, trustees’ fees, and out-of-pocket expenses) are recorded on an accrual basis.

	c.		Cash reserves may be established by the Trustee for certain contingencies that would not be recorded under generally accepted accounting principles.

	d.		Amortization of the Royalty Interest is calculated based on the units of production method. Such amortization is charged directly to the Trust Corpus, and does not affect cash earnings. The daily rate for amortization per net equivalent barrel of oil for the years ended December 31, 2005, 2004, and 2003 was $0.37. The Trust evaluates impairment of the Royalty Interest by comparing the undiscounted cash flows expected to be realized from the Royalty Interest to the carrying value, pursuant to Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the Royalty Interest.

		While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful because quarterly distributions to the Trust Unit Holders are based on net cash receipts. The accompanying modified cash basis financial statements contain all adjustments necessary to present fairly the assets, liabilities and Corpus of the Trust as of December 31, 2005 and 2004, and the modified cash earning and distributions and changes in Trust Corpus for the years ended December 31, 2005, 2004 and 2003. The adjustments are of a normal recurring nature and are, in the opinion of the Trustee, necessary to fairly present the results of operations.

		As of December 31, 2005 and 2004, cash equivalents which represent the cash reserve consist of U.S. treasury bills with an initial term of less than three months.

Estimates and assumptions are required to be made regarding assets, liabilities and changes in Trust Corpus resulting from operations when financial statements are prepared. Changes in the economic

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005

environment, financial markets and any other parameters used in determining these estimates could cause actual results to differ, and the difference could be material.

(3)		Royalty Interest

		The Royalty Interest is comprised of the following at December 31, 2005 and 2004 (in thousands):


	December 31,
	2005			2004
Royalty Interest (at inception)	$	535,000		$	535,000
Less: Accumulated amortization		(351,439	)		(349,431	)
Impairment write-down		(173,518	)		(173,518	)


Balance, end of period	$	10,043		$	12,051

(4)		Income Taxes

		The Trust files its federal tax return as a grantor trust subject to the provisions of subpart E of Part I of Subchapter J of the Internal Revenue Code of 1986, as amended, rather than as an association taxable as a corporation. The Trust Unit Holders are treated as the owners of Trust income and Corpus, and the entire taxable income of the Trust will be reported by the Trust Unit Holders on their respective tax returns.

		If the Trust were determined to be an association taxable as a corporation, it would be treated as an entity taxable as a corporation on the taxable income from the Royalty Interest, the Trust Unit Holders would be treated as shareholders, and distributions to Trust Unit Holders would not be deductible in computing the Trust’s tax liability as an association.

(5)		Subsequent Event

		In February 2006 the Governor of Alaska announced that the State and BP Alaska, ConocoPhilips and ExxonMobil had reached agreement in principle on a natural gas pipeline contract. The proposed natural gas pipeline would run from Alaska’s North Slope through Canada and into the Midwestern United States and would be completed in six to eight years. The Governor also announced that he had proposed legislation to reform the state’s oil production tax. The proposed oil and gas production tax would replace the current production tax on oil, which is based on a percentage of the gross value of production. Under the Governor’s proposed bill, producers will pay a tax on net profits and will receive a tradable capital investment tax credit and a standard deduction. The gas pipeline contract is not final or public and the Governor’s tax bill has not been enacted by the Alaska legislature. It is not certain that the pipeline will be constructed or that the petroleum production tax will be enacted in the form proposed by the Governor.

		If the proposed gas pipeline is constructed, extraction of natural gas from the Field will lower reservoir pressure and may accelerate the decline in production from the reserve volumes attributable to the Trust and the time at which royalty payments to the Trust will cease. The Trust is not entitled to any royalty payments with respect to natural gas production from the Field.

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005

The Per Barrel Royalty payable to the Trust could be reduced if a new Alaska petroleum production tax results in an effective rate of tax chargeable against the Royalty Interest that is higher than the current tax imposed on wellhead value of production.

(6)		Summary of Quarterly Results (Unaudited)

		A summary of selected quarterly financial information for the years ended December 31, 2005, 2004, and 2003 is as follows (in thousands, except unit data):


	2005 Fiscal Quarter
	First			Second			Third			Fourth
Royalty revenues	$	33,197			33,413			37,357			49,011
Interest income		5			9			11			12
Trust administrative expenses		(151	)		(367	)		(388	)		(191	)

Cash earnings		33,051			33,055			36,980			48,832
Cash distributions		33,051			33,060			36,971			48,826
Cash distributions per unit		1.5444			1.5449			1.7276			2.2816


	2004 Fiscal Quarter
	First			Second			Third			Fourth
Royalty revenues	$	14,659			18,342			21,566			28,115
Interest income		2			3			2			4
Trust administrative expenses		(216	)		(324	)		(212	)		(224	)

Cash earnings		14,445			18,021			21,356			27,895
Cash distributions		14,343			18,109			21,352			27,898
Cash distributions per unit		0.6702			0.8462			0.9978			1.3036


	2003 Fiscal Quarter
	First			Second			Third			Fourth
Royalty revenues	$	12,538			17,722			12,147			13,579
Interest income		4			2			2			2
Trust administrative expenses		(469	)		(333	)		(225	)		(141	)

Cash earnings		12,073			17,391			11,924			13,440
Cash distributions		12,412			17,291			11,823			13,341
Cash distributions per unit		0.580			0.808			0.553			0.623


	Fiscal Year Ended
	2005			2004			2003
Royalty revenues	$	152,978			82,682			55,986
Interest income		37			11			10
Trust administrative expenses		(1,097	)		(976	)		(1,168	)

Cash earnings		151,918			81,702			54,828
Cash distributions		151,908			81,702			54,867
Cash distributions per unit		7.098			3.818			2.564

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005

(7)		Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Reserves (Unaudited)

		Pursuant to Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities (“FASB 69”), the Trust is required to include in its financial statements supplementary information regarding estimates of quantities of proved reserves attributable to the Trust and future net cash flows.

		Estimates of proved reserves are inherently imprecise and subjective and are revised over time as additional data becomes available. Such revisions may often be substantial. Information regarding estimates of proved reserves attributable to the combined interests of BP Alaska and the Trust were based on reserve estimates prepared by BP Alaska. BP Alaska’s reserve estimates are believed to be reasonable and consistent with presently known physical data concerning the size and character of the Field.

		There is no precise method of allocating estimates of physical quantities of reserve volumes between BP Alaska and the Trust, since the Royalty Interest is not a working interest and the Trust does not own and is not entitled to receive any specific volume of reserves from the Field. Reserve volumes attributable to the Trust were estimated by allocating to the Trust its share of estimated future production from the Field, based on the WTI Price on December 31, 2005 ($61.04 per barrel), December 31, 2004 ($43.46 per barrel) and December 31, 2003 ($32.55 per barrel). Because the reserve volumes attributable to the Trust are estimated using an allocation of reserve volumes based on the estimated future production and on the current WTI Price, a change in the timing of estimated production or a change in the WTI price will result in a change in the Trust’s estimated reserve volumes. Therefore, the estimated reserve volumes attributable to the Trust will vary if different production estimates and prices are used.

		In addition to production estimates and prices, reserve volumes attributable to the Trust are affected by the amount of Chargeable Costs that will be deducted in determining the Per Barrel Royalty. Net proved reserves of oil and condensate attributable to the Trust as of December 31, 2005, 2004 and 2003, based on BP Alaska’s latest reserve estimate at such time and the WTI Prices on December 31, 2005, 2004 and 2003, were estimated to be 85, 77 and 78 million barrels, respectively (of which 73, 68 and 67 million barrels, respectively, are proved developed). Under the provisions of FASB 69, no consideration can be given to reserves not considered proved at the present time.

		The standardized measure of discounted future net cash flow relating to proved reserves disclosure required by FASB 69 assigns monetary amounts to proved reserves based on current prices. This discounted future net cash flow should not be construed as the current market value of the Royalty Interest. A market valuation determination would include, among other things, anticipated price changes and the value of additional reserves not considered proved at the present time or reserves that may be produced after the currently anticipated end of field life. At December 31, 2005, 2004 and 2003, the standardized measure of discounted future net cash flow relating to proved reserves attributable to the Trust (estimated in accordance with the provisions of FASB 69), based on the WTI Prices on those dates of $61.04, $43.46 and $32.55, respectively, were as follows (in thousands):

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005


	December 31,
	2005			2004			2003
Future net cash flows	$	2,095,163		$	1,130,851		$	644,691
10% annual discount for estimated timing of cash flows		(885,424	)		(454,532	)		(249,373	)


Standardized measure of discounted future net cash flow relating to proved reserves (a)	$	1,209,739		$	676,319		$	395,318


(a)		The following are the principal sources of the change in the standardized measure of discounted future net cash flows (in thousands):


	December 31,
	2005			2004			2003
Revisions of prior estimates:
Reserve volumes	$	2,472		$	6,123		$	(3,915	)
WTI price		787,204			494,363			56,270
Adjusted chargeable costs		(33,736	)		(80,201	)		(15,712	)
Production taxes		(116,558	)		(72,641	)		(7,666	)
Other		(370	)		(15	)		8

		639,012			347,629			28,985

Royalty income received (b)		(173,224	)		(106,160	)		(60,943	)
Accretion of discount		67,632			39,532			38,843


Net increase during the year	$	533,420		$	281,001		$	6,885


(b)		For the purpose of this calculation, royalty income received for 2005, 2004 and 2003 includes the following:


Period October 1, 2005 through December 31, 2005	$	45,246
Period October 1, 2004 through December 31, 2004	$	33,197
Period October 1, 2003 through December 31, 2003	$	14,659

The above royalty income was received by the Trust in January 2006, 2005 and 2004, respectively.

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005

The changes in quantities of proved oil and condensate were as follows (in thousands of barrels):


Estimated net proved reserves of oil and condensate at December 31, 2003	77,942
Production	(5,410	)
Reserve estimate revisions	635
Change caused by prices/costs	4,237


Estimated net proved reserves of oil and condensate at December 31, 2004	77,404
Production	(5,395	)
Reserve estimate revisions	(1,711	)
Change caused by prices/costs	15,015


Estimated net proved reserves of oil and condensate at December 31, 2005	85,313


Proved reserves:

December 31, 2003	77,942


December 31, 2004	77,404


December 31, 2005	85,313

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There have been no changes in accountants and no disagreements with accountants on any matter of accounting principles or practices or financial statement disclosures during the two fiscal years ended December 31, 2005.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Trustee has disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Exchange Act) that are designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s 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 Alaska’s estimates of future net cash flows from proved reserves attributable to the Royalty Interest, the discounted present value of such proved reserves, the assumptions utilized in arriving at the estimates contained in the report, and the estimate of the quantities of proved reserves (including reductions of proved reserves as a result of modification of BP Alaska’s estimates of proved reserves from prior years) added during the preceding year to the total proved reserves allocated to the BP Working Interests as of December 31, 1987. (See “THE ROYALTY INTEREST – Chargeable Costs” in Item 1.)

In addition, the Conveyance gives the Trust and its independent accountants certain rights to inspect the books and records of BP Alaska and discuss the affairs, finances and accounts of BP Alaska relating to the BP Working Interests with representatives of BP Alaska; it also requires BP Alaska to provide the Trust with such other information as the Trustee may reasonably request from time to time and to which BP Alaska has access.

The Trustee’s disclosure controls and procedures include ensuring that the Trust receives the information and reports that BP Alaska is required to furnish to the Trust on a timely basis, that the appropriate responsible personnel of the Trustee examine such information and reports, and that information requested from and provided by BP Alaska is included in the reports that the Trust files or submits under the Exchange Act.

As of the end of calendar 2005, the trust officers of the Trustee responsible for the administration of the Trust conducted an evaluation of the Trust’s 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 Trust’s disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

Management’s Annual Report on Internal Control Over Financial Reporting. The Bank of New York, as Trustee of the Trust, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). Based on the Trustee’s evaluation under the COSO criteria, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2005.

The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report set forth in full below.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Trustee and Holders of Trust Units of BP Prudhoe Bay Royalty Trust:

We have audited the trustee’s assessment, included in the Trustee’s Report on Internal Control over Financial Reporting under Item 9A of the accompanying Annual Report on Form 10-K, that BP Prudhoe Bay Royalty Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of BP Prudhoe Bay Royalty Trust is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the trustee’s assessment and an opinion on the effectiveness of the Trust’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating the trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting. A trust’s 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 trust’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the trustee’s assessment that BP Prudhoe Bay Royalty Trust maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, BP Prudhoe Bay Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal 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, 2005 and 2004, and the related statements of cash earnings and distributions and changes in trust corpus for each of the years in the three-year period ended December 31, 2005, and our report dated March 15, 2006 expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described the Trust’s method of accounting as explained in Note 2 to the financial statements.

KPMG LLP

Dallas, Texas

March 15, 2006

Changes in Internal Control Over Financial Reporting. There has not been any change in the Trust’s internal control over financial reporting identified in connection with the Trustee’s evaluation of the Trust’s internal control over financial reporting that occurred during the Trust’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Trust has no directors or executive officers. The Trustee has only such rights and powers as are necessary to achieve the purposes of the Trust.

ITEM 11. EXECUTIVE COMPENSATION

The Trust has no directors, officers or employees to whom it pays compensation. The Trust is administered by employees of the Trustee in the ordinary course of their employment by the Trustee and receive no compensation specifically related to their services to the Trust.

The compensation received by the Trustee from the Trust during the three fiscal years ended December 31, 2005 was as follows:


			Transfer Agent and
			Registrar
Year ended December 31,	Trustee’s Fees		Fees
2005	$	141,288	$	7,075
2004		116,378		6,647
2003		114,572		7,381

Under the Trust Agreement, the Trustee is entitled to receive on each Quarterly Record Date a quarterly fee consisting of: (i) a quarterly administrative fee of $.0011 per Unit outstanding on the Quarterly Record Date and (ii) a transfer service fee of $1.50 per Unit holder account as of the Quarterly Record Date. Both the administrative service fee and the transfer service fee are subject to increase by the proportionate increase, if any, during the preceding calendar year in the Consumer Price Index during the preceding calendar year. The Trustee also bills the Trust for certain reimbursable expenses.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Securities Authorized for Issuance under Equity Compensation Plans

No Units are authorized for issuance under any form of equity compensation plan.

Unit Ownership of Certain Beneficial Owners

As of March 16, 2006, there were no persons known to the Trustee to be the beneficial owners of more than five percent of the Units.

Unit Ownership of Management

Neither BP Alaska, Standard Oil, nor BP owns any Units. No Units are owned by The Bank of New York, as Trustee or in its individual capacity, or by The Bank of New York (Delaware), as co-trustee or in its individual capacity.

Changes in Control

The Trustee knows of no arrangement, including the pledge of Units, the operation of which may at a subsequent date result in a change in control of the Trust.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Not applicable.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Fees for services performed by KPMG LLP for the years ended December 31, 2005 and 2004 are:


	2005		2004
Audit		113,000	$	108,000
Audit related		16,000		14,500
Tax		200,000		200,000
Other		—		—

	$	329,000	$	322,500

The Trust has no audit committee, and as a consequence, has no audit committee pre-approval policy with respect to fees paid to KPMG LLP.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) FINANCIAL STATEMENTS

The following financial statements of the Trust are included in Part II, Item 8:

Report of Independent Registered Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus as of December 31, 2005 and 2004

Statements of Cash Earnings and Distributions for the years ended December 31, 2005, 2004 and 2003

Statements of Changes in Trust Corpus for the years ended December 31, 2005, 2004 and 2003

Notes to Financial Statements

(b) FINANCIAL STATEMENT SCHEDULES

All financial statement schedules have been omitted because they are either not applicable, not required or the information is set forth in the financial statements or notes thereto.

4.1

BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee.

4.2		Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc. and The Standard Oil Company.

4.3		Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay Royalty Trust.

4.4		Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.

31		Rule 13a-14(a) certification.

32		Section 1350 certification.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		BP PRUDHOE BAY ROYALTY TRUST

		By:		THE BANK OF NEW YORK, as Trustee

		By:		/s/ Ming J. Ryan Ming J. Ryan
				Vice President

March 16, 2006

The Registrant is a trust and has no officers, directors, or persons performing similar functions. No additional signatures are available and none have been provided.

INDEX TO EXHIBITS


Exhibit No.		Description
4.1*		BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee.

4.2*		Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc. and The Standard Oil Company.

4.3*		Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay Royalty Trust.

4.4*		Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.

31		Rule 13a-14(a) certification. Filed herewith

32		Section 1350 certification. Filed herewith.


*		Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 1996 (File No. 1-10243).