SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

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

For the quarterly period ended September 30, 2006

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

For the transition period from                      to                     

BP PRUDHOE BAY ROYALTY TRUST

(Exact Name of Registrant as Specified in Its Charter)

Delaware		13-6943724
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
The Bank of New York, 101 Barclay Street, New York, NY		10286
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: (212) 815-6908

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

     Indicate by check mark whether the registrant 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

     As of November 9, 2006, 21,400,000 Units of Beneficial Interest were outstanding.

 

 

PART I

Item 1. Financial Statements

BP Prudhoe Bay Royalty Trust

Statement of Assets, Liabilities and Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements)
(Unaudited)

(In thousands, except unit data)

		September 30,				December 31,
		2006				2005
Assets
Royalty Interest, net (Notes 1, 2 and 3)		$	8,536			$	10,043
Cash and cash equivalents (Note 2)			1,011				1,011
Total Assets		$	9,547			$	11,054
Liabilities and Trust Corpus
Accrued expenses		$	346			$	178
Trust Corpus (40,000,000 units of beneficial interest authorized, 21,400,000 units issued and outstanding)			9,201				10,876
Total Liabilities and Trust Corpus		$	9,547			$	11,054

See accompanying notes to financial statements (unaudited).

BP Prudhoe Bay Royalty Trust

Statements of Cash Earnings and Distributions
(Prepared on a modified basis of cash receipts and disbursements)
(Unaudited)

(In thousands, except unit data)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
Royalty revenues		$	55,797			$	37,357			$	148,719			$	103,967
Interest income			22				11				54				25
Less: Trust administrative expenses			(279	)			(388	)			(732	)			(906	)
Cash earnings		$	55,540			$	36,980			$	148,041			$	103,086
Cash distributions		$	55,538			$	36,971			$	148,042			$	103,082
Cash distributions per unit		$	2.5952			$	1.7276			$	6.9179			$	4.8169
Units outstanding			21,400,000				21,400,000				21,400,000				21,400,000

See accompanying notes to financial statements (unaudited).

BP Prudhoe Bay Royalty Trust

Statements of Changes in Trust Corpus
(Prepared on a modified basis of cash receipts and disbursements)
(Unaudited)

(In thousands)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2006				2005				2006				2005
Trust Corpus at beginning of period		$	9,747			$	11,635			$	10,876			$	12,881
Cash earnings			55,540				36,980				148,041				103,086
Decrease (increase) in accrued expenses			(46	)			198				(167	)			(39	)
Cash distributions			(55,538	)			(36,971	)			(148,042	)			(103,082	)
Amortization of Royalty Interest			(502	)			(502	)			(1,507	)			(1,506	)
Trust Corpus at end of period		$	9,201			$	11,340			$	9,201			$	11,340

See accompanying notes to financial statements (unaudited).

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements (Unaudited)
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
September 30, 2006

(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 (the “Trust Agreement”). Standard Oil and BP Alaska are indirect wholly-owned subsidiaries of BP p.l.c. (“BP”).
		On February 28, 1989, Standard Oil conveyed an overriding royalty interest (the “Royalty Interest”) to the Trust. The Trust was formed for the sole purpose of owning and administering the Royalty Interest. The Royalty Interest represents the right to receive, effective February 28, 1989, a per barrel royalty (the “Per Barrel Royalty”) of 16.4246% on the lesser of (a) the first 90,000 barrels of the average actual daily net production of oil and condensate per quarter or (b) the average actual daily net production of oil and condensate per quarter from BP Alaska’s working interest as of February 28, 1989 in the Prudhoe Bay Field situated on the North Slope of Alaska (the “BP Working Interests”). 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. See Note 6 for information concerning a recent partial shutdown of the Prudhoe Bay Field. BP has guaranteed the performance of BP Alaska of its payment obligations with respect to the Royalty Interest.
		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). See Note 5 for information concerning a change in Alaska oil and gas production taxes which affects the calculation of the Per Barrel Royalty.
		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

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements (Unaudited)
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
September 30, 2006

expenses, in the month succeeding the end of each calendar quarter. The Trust will terminate upon the first to occur of the following events:

	a.		On or prior to December 31, 2010: upon a vote of Trust Unit Holders of not less than 70% of the outstanding Trust Units.
	b.		After December 31, 2010: (i) upon a vote of Trust Unit Holders of not less than 60% of the outstanding Trust Units, or (ii) at such time the net revenues from the Royalty Interest for two successive years commencing after 2010 are less than $1,000,000 per year (unless the net revenues during such period are materially and adversely affected by certain events).

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 three months ended September 30, 2006 and 2005 was $0.56 and $0.37, respectively, and for the nine months ended September 30, 2006 and 2005 it was $0.42 and $0.37, respectively. The Trust evaluates impairment of the Royalty Interest by comparing the undiscounted cash flows expected to be realized from the Royalty Interest to the carrying value, pursuant to Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” 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.

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements (Unaudited)
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
September 30, 2006

		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 September 30, 2006 and 2005, and the modified cash earning and distributions and changes in Trust Corpus for the three-month and nine-month periods ended September 30, 2006 and 2005. The adjustments are of a normal recurring nature and are, in the opinion of the Trustee, necessary to fairly present the results of operations.
		As of September 30, 2006 and December 31, 2005, cash equivalents which represent the cash reserve consist of US treasury bills with an initial term of less than three months.
		Estimates and assumptions are required to be made regarding assets, liabilities and changes in Trust Corpus resulting from operations when financial statements are prepared. Changes in the economic environment, financial markets and any other parameters used in determining these estimates could cause actual results to differ, and the differences could be material.
		The financial statements should be read in conjunction with the financial statements and related notes in the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005. The cash earnings and distributions for the interim period presented are not necessarily indicative of the results to be expected for the full year.

(3)

Royalty Interest

The Royalty Interest is comprised of the following at September 30, 2006 and December 31, 2005 (in thousands):

		September 30,				December 31,
		2006				2005
Royalty Interest (at inception)		$	535,000			$	535,000
Less: Accumulated amortization			(352,946	)			(351,439	)
Impairment write-down			(173,518	)			(173,518	)
Balance, end of period		$	8,536			$	10,043

(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

BP Prudhoe Bay Royalty Trust
Notes to Financial Statements (Unaudited)
(Prepared on a Modified Basis of Cash Receipts and Disbursements)
September 30, 2006

		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)		Alaska Oil and Gas Production Tax
		On August 20, 2006 a new Alaska oil and gas production tax (the “New Tax”) became effective. The New Tax replaced an oil production tax levied at the flat rate of 15% of the gross value at the point of production of taxable oil produced from a producer’s leases or properties in the State of Alaska and is retroactive to April 1, 2006.
		Under the New Tax, producers are taxed on the “production tax value of taxable oil” (gross value at the point of production for the calendar year less the producer’s direct costs of exploring for, developing, or producing oil or gas deposits located within the producer’s leases or properties in Alaska for the year) at a rate equal to the sum of 22.5% plus a “progressivity” rate determined by the average monthly production tax value of the oil produced. The progressivity portion of the New Tax is equal to 0.25% times the amount by which the simple average for each calendar month of the daily taxable values per barrel of the oil produced during the month exceeds $40 per barrel.
		The Trustee and BP Alaska entered into a letter agreement (the “Letter Agreement”) to resolve the major issues associated with the New Tax. The Letter Agreement modified the calculation of Production Taxes in the daily Per Barrel Royalty calculation effective as of August 20, 2006. It also provides that the retroactivity provisions of the New Tax are not applicable to the Per Barrel Royalty calculation for periods prior to August 20, 2006. Giving effect to the principles set forth in the Letter Agreement, the Production Tax component of the Per Barrel Royalty Calculation was $10.11 for the period from July 1, 2006 through August 19, 2006, $13.21 for the period from August 20, 2006 through August 31, 2006 and $10.60 for the period from September 1, 2006 through September 30, 2006.

(6)		Partial Shutdown of Prudhoe Bay Oil Field
		On August 7, 2006, BP announced that BP Alaska had commenced a shutdown of the Prudhoe Bay Field as a result of the discovery of unexpectedly severe corrosion and a small spill from an oil transit line in the Prudhoe Bay Field. BP subsequently determined to shut down only the Eastern Operating Area of the field and continue production from the Western Operating Area. The partial shutdown of the Prudhoe Bay Field reduced average daily production from the field to approximately half of normal output. Actual average daily net production from the BP Working Interests during the quarter ended September 30, 2006 was

		approximately 59,300 barrels per day. Clearance from the U.S. Department of Transportation to restart production in the Eastern Operating Area was received in September 2006 and Prudhoe Bay output was reported to have returned to its pre-shutdown level of over 400,000 barrels per day by late October 2006.

Item 2. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.

Cautionary Statement

This report contains 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 Item 1A, “Risk Factors,” of the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005 (the “Annual Report”) and in Item 1A of Part II 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 the Annual Report and 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.

Liquidity and Capital Resources

The BP Prudhoe Bay Royalty Trust (the “Trust”) is a passive entity, and the activities of The Bank of New York, as trustee of the Trust (the “Trustee”) are limited to collecting and distributing the revenues from the overriding royalty interest held by the Trust (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 Part I, Item 1 of the Annual Report for additional information concerning the Royalty Interest, and the discussion under “THE PRUDHOE BAY UNIT AND FIELD — Reserve Estimates” and “INDEPENDENT OIL AND GAS CONSULTANTS’ REPORT” in Part I, Item 1 of the Annual Report for information concerning the estimated future net revenues of the Trust. However, the Trustee has a limited power to borrow, establish a cash reserve, or dispose of all or part of the Trust estate, under limited circumstances pursuant to the terms of the Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc. (“BP Alaska”), the Trustee and The Bank of New York (Delaware), as co-trustee (the “Trust Agreement”). See the discussion under “THE TRUST” in Part I, Item 1 of the Annual Report.

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 holders of Units on each Quarterly Record Date.

As discussed under “CERTAIN TAX CONSIDERATIONS” in Part I, Item 1 of the Annual Report, amounts received by the Trust as quarterly distributions are income to the holders of the Units (as are any earnings on investment of the cash reserve) and must be reported by the holders of the Units even if such amounts are used to repay borrowings or replenish the cash reserve and are not received by the holders of the Units.

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.

Under the terms of the Conveyance of the Royalty Interest to the Trust, 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. The narrative under the captions “THE TRUST – Trust Property” and “THE ROYALTY INTEREST” in the Annual Report explains the meanings of the terms “Conveyance,” “Royalty Interest,” “Per Barrel Royalty,” “WTI Price, “Chargeable Costs” and “Cost Adjustment Factor” and should be read in conjunction with this report.

Royalty revenues are generally received on the fifteenth day of the month following the end of the calendar quarter in which the related Royalty Production occurred (the “Quarterly Record Date”). The Trustee, to the extent possible, pays all accrued expenses of the Trust 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 modified cash basis and, as a result, royalties paid to the Trust and distributions to Unit holders in the quarters ended September 30, 2006 and 2005, respectively, are attributable to BP Alaska’s operations during the quarters ended June 30, 2006 and 2005, respectively.

The following table show the factors which were employed to compute the Per Barrel Royalty payments received by the Trust during the first three quarters of 2006 and 2005. The information in the table has been furnished by BP Alaska.

										Cost				Adjusted
		Average				Chargeable				Adjustment				Chargeable				Production				Per Barrel
		WTI Price				Costs				Factor				Costs				Taxes*				Royalty
Calendar 2006
4th Qtr 2005		$	60.01			$	12.25				1.521			$	18.63			$	8.01			$	33.37
1st Qtr 2006			63.36				12.50				1.530				19.13				8.50				35.73
2nd Qtr 2006			70.53				12.50				1.559				19.49				9.56				41.48
Calendar 2005
4th Qtr 2004		$	48.35			$	12.00				1.471			$	17.65			$	6.29			$	24.41
1st Qtr 2005			49.70				12.25				1.477				18.09				6.49				25.12
2nd Qtr 2005			53.09				12.25				1.497				18.34				6.98				27.77

“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 parts of the Prudhoe Bay (Permo-Triassic) Reservoir 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”). As long as BP Alaska’s average daily net production from the BP Working Interests in the Prudhoe Bay Unit exceeds 90,000 barrels, which BP Alaska currently projects will continue until the year 2012, the principal 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 and changes in Production Taxes. See, however, Item 1A in Part II of this report for information concerning the recent partial shutdown of the Prudhoe Bay field. BP Alaska reports that actual average daily net production from the BP Working Interests during the quarter ended September 30, 2006 was approximately 59,300 barrels per day.

On August 20, 2006 a new Alaska oil and gas production tax (the “New Tax”) became effective. The New Tax replaced an oil production tax levied at the flat rate of 15% of the gross value at the point of production of taxable oil produced from a producer’s leases or properties in the State of Alaska (the “Old Tax”) and is retroactive to April 1, 2006.

Under the New Tax, producers are taxed on the “production tax value of taxable oil” (gross value at the point of production for the calendar year less the producer’s direct costs of exploring for, developing, or producing oil or gas deposits located within the producer’s leases or properties in Alaska (“Lease Expenditures”) for the year) at a rate equal to the sum of 22.5% plus a “progressivity” rate determined by the average monthly production tax value of the oil produced. The progressivity portion of the New Tax is equal to 0.25% times the amount by which the simple average for each calendar month of the daily taxable values per barrel of the oil produced during the month exceeds $40 per barrel.

Section 4.6 of the Conveyance provides that “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.

In order to resolve uncertainties in the interpretation of Section 4.6 of the Conveyance resulting from the New Tax, the Trustee entered into a letter agreement with BP Alaska (the “Letter Agreement”) which is filed as Exhibit 4.5 to this report. The Letter Agreement sets forth consensus principles agreed by the parties to resolve two major issues presented by the New Tax: (1) how the amount of the New Tax chargeable against the Royalty Interest is to be determined under the Conveyance; and (2) the extent, if any, to which the retroactivity of the New Tax is to be recognized for purposes of the Conveyance (the “Consensus Principles”).

The Consensus Principles set forth in the Letter Agreement are the following:

1.		Calculation of the amount of New Tax chargeable against the Royalty Interest.
		The amount of New Tax chargeable against the Royalty Interest under the Conveyance will be determined as follows:

a) The taxable value per barrel equals the WTI Price minus the Chargeable Costs as adjusted by the Cost Adjustment Factor.

b) The tax rate for the “progressivity” portion of the New Tax equals 0.25 percentage points times the amount by which the simple average for each calendar month of the daily taxable values per barrel under “a)” above exceeds $40 per barrel. If that average taxable value per barrel is $40 or less, the “progressivity” rate is zero. The $40 figure is not subject to adjustment over time.

c) The amount of New Tax chargeable against the Royalty Interest equals the taxable value per barrel under “a)” above times the Royalty Production under the Conveyance, times a rate equal to the sum of 22.5% plus the “progressivity” rate determined under “b)” above.

2.		Retroactivity of the New Tax.
		The tax chargeable against the Royalty Interest for Prudhoe Bay oil produced during the period from April 1 to August 19, 2006, inclusive, is the amount of Old Tax as calculated under Section 4.6 of the Conveyance for that production. For Prudhoe Bay oil produced on August 20, 2006 and thereafter, the tax chargeable against the Royalty Interest under Section 4.6 is the amount of New Tax determined as prescribed in “1” above for that production. The “progressivity” rate under the New Tax for August 2006 will be calculated under “1.b)” above using the average of the daily WTI Prices for August 20 to August 31, 2006, inclusive.

The following tables show the application of the Consensus Principles to the calculation of the royalty payment received by the Trust with respect to the third quarter of 2006:

Royalty Distribution Calculation**

		July 1 – Aug 19				Aug 20 – Aug 31				Sep 1 – Sep 30				Total
WTI Price*		$	74.29			$	71.40			$	64.25
Chargeable Costs
x Cost Adj. Factor*			(19.63	)			(19.63	)			(19.63	)
Production Taxes*			(10.11	)			(13.21	)			(10.60	)
Per Barrel Royalty*			44.55				38.56				34.03
Royalty Production			486,972				116,873				292,183				896,028
Royalty Payment		$	21,694,561			$	4,507,085			$	9,943,352			$	36,144,998

Production Tax Calculation

		July 1 – Aug 19				Aug 20 – Aug 31				Sep 1 – Sep 30
WTI Price*		$	74.29			$	71.40			$	64.25
Transportation ($4.50 x Cost Adj. Factor)*			(7.07	)			(7.07	)			(7.07	)
Wellhead or field value*			67.22				64.33				57.18
Lease Expenditures (Chargeable Costs – Transportation)*							(12.56	)			(12.56	)
Taxable value*							51.77				44.62
Statutory rate (see below)			15	%			25.44	%			23.66	%
AK production tax*			10.08				13.17				10.56
AK production tax surcharge*			0.03				0.04				0.04
Production Taxes*		$	10.11			$	13.21			$	10.60

Progressivity Rate Calculation

Monthly average taxable value*		$	51.77			$	44.62
Base for progressivity*			40.00				40.00
Excess value (>$40)*			11.77				4.62
Progressivity factor			0.25	%			0.25	%
Progressivity rate			2.94	%			1.16	%
Base rate			22.50	%			22.50	%
Statutory rate			25.44	%			23.66	%

Quarter Ended September 30, 2005

As explained above, Trust royalty revenues received during the third quarter of the fiscal year are based on Royalty Production during the second quarter of the fiscal year. As a consequence, royalty revenues received by the Trust in the third quarter were not affected by the partial shutdown of the Prudhoe Bay field, which commenced in August 2006, or by the enactment of the New Tax. Royalty revenues received by the Trust in the quarter ended September 30, 2006

increased 49.4% from the revenues received in the corresponding quarter of 2005, due to a 32.9% period-to-period increase in the Average WTI Price from $53.09 per barrel during the quarter ended June 30, 2005 to $70.53 per barrel during the quarter ended June 30, 2006. A 14.9% period-to-period increase in total deductible costs from $25.32 per barrel to $29.08 per barrel was due principally to a 40.0% increase in Production Taxes chargeable with respect to the quarter ended June 30, 2006, and partially offset the effect of the increase in the Average WTI Price on the Trust's revenues.

Nine Months Ended September 30, 2005

Trust royalty revenues increased 43.0% in the nine months ended September 30, 2006 over the corresponding period in 2005, reflecting the cumulative effect of increases in revenues received during the last quarter of 2005 and the first two quarters of 2006 over revenues received during the corresponding periods of 2004 and 2005. The revenue increase resulted from continued increases in Average WTI Prices during recent periods, which averaged $64.63 per barrel during the nine months ended June 30, 2006 compared to an average of $50.38 per barrel during the nine months ended June 30, 2005. A 12.8% increase in average total deductible costs charged during the three quarters ended June 30, 2006 over the corresponding average deductible costs during the three quarters ended June 30, 2005, due principally to increases in Production Taxes, partially offset the effect of the increases in the Average WTI Prices per barrel on the Trust’s revenues.

Item 3. 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 4. 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.

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 the period covered by this report, 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

There has not been any change in the Trust’s internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Trust’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

PART II

Item 1. Legal Proceedings.

None.

Item 1A. Risk Factors

          1. The following paragraphs replace a risk factor described in Part II, Item 1A in the Trust’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 which appears under the heading “Bills pending in the Alaska Legislature to repeal Alaska’s current oil production tax and provide for a new basis of taxation on the production of oil may result in higher production tax deductions from royalty payments to the Trust”:

§

Distributions by the Trust will be affected by amendments to the Alaska oil and gas production tax.

     On August 20, 2006, a new Alaska oil and gas production tax (the “New Tax”) became effective. The New Tax replaced an oil production tax levied at the flat rate of 15% of the gross value at the point of production of taxable oil produced from a producer’s leases or properties in the State of Alaska (the “Old Tax”).

     Under the New Tax, producers are taxed on the “production tax value of taxable oil” (gross value at the point of production for the calendar year less the producer’s direct costs of exploring for, developing, or producing oil or gas deposits located within the producer’s leases or properties in Alaska (“Lease Expenditures”) for the year) at a rate equal to the sum of 22.5% plus a “progressivity” rate determined by the average monthly production tax value of the oil produced. The progressivity portion of the New Tax is equal to 0.25% times the amount by which the simple average for each calendar month of the daily taxable values per barrel of the oil produced during the month exceeds $40 per barrel.

      As a consequence of the enactment of the New Tax, the payment by BP Alaska of the Per Barrel Royalty to the Trust with respect to the quarter ended September 30, 2006 was lower than it would have been under the Old Tax and the Trustee expects that future royalty payments also will be reduced. The magnitude of the effect of the New Tax on royalty payments for any quarter cannot be predicted due to the progressivity feature of the New Tax. See the “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I, Item 2 of this report for a discussion of the application of the New Tax to the calculation of the Per Barrel Royalty.

          2. The following paragraph supplements a risk factor described in Part II, Item 1A of the Trust’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006 which appears under the heading “The shutdown of the Prudhoe Bay oil field may result in materially reduced distributions or no quarterly distributions to Unitholders for an indefinite period”:

     Although BP announced on August 7, 2006 that BP Alaska had commenced a shutdown of the entire Prudhoe Bay field, BP subsequently determined to shut down only the Eastern Operating Area of the field and continue production from the Western Operating Area. The partial shutdown of the Prudhoe Bay field reduced average daily production from the field to approximately half of normal output. On September 22, 2006, BP announced that it had received clearance from the U.S. Department of Transportation to restart production in the Eastern Operating Area. The Anchorage Daily News reported on October 28, 2006 that Prudhoe Bay output has returned to its pre-shutdown level of over 400,000 barrels per day.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

	(a)		Not applicable.
	(b)		Not applicable.

Item 6. Exhibits.

4.1		BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee.
4.2		Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc. and The Standard Oil Company.
4.3		Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay Royalty Trust.
4.4		Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.
4.5		Letter agreement dated October 13, 2006 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee.
31		Rule 13a-14(a)/15d-14(a) Certification.
32		Section 1350 Certification.

SIGNATURE

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

		BP PRUDHOE BAY ROYALTY TRUST
		By:		THE BANK OF NEW YORK,
				as Trustee
		By:		/s/ Remo Reale
				Remo Reale
				Vice President
Date: November 9, 2006

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

INDEX TO EXHIBITS

Exhibit		Exhibit
No.		Description
*4.1		BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee.
*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.
**4.5		Letter agreement dated October 13, 2006 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee.
**31.		Rule 13a-14(a)/15d-14(a) Certification.
**32		Section 1350 Certification.