BP PRUDHOE BAY ROYALTY TRUST - Quarter Report: 2012 September (Form 10-Q)

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

For the quarterly period ended September 30, 2012

OR

For the transition period from             to             

Commission file number 1-10243

BP PRUDHOE BAY ROYALTY TRUST

(Exact Name of Registrant as Specified in Its Charter)

Registrant’s Telephone Number, Including Area Code: (512) 236-6565

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (17 CFR § 232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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

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

As of November 9, 2012, 21,400,000 Units of Beneficial Interest were outstanding.

PART I

FINANCIAL INFORMATION

BP Prudhoe Bay Royalty Trust

Statements of Assets, Liabilities and Trust Corpus

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

(In thousands, except unit data)

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)

See accompanying notes to financial statements (unaudited).

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BP Prudhoe Bay Royalty Trust

Statements of Changes in Trust Corpus

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

(Unaudited)

(In thousands)

See accompanying notes to financial statements (unaudited).

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BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a Modified Basis of Cash Receipts and Disbursements)

September 30, 2012

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 (the “Trust Agreement”) among The Standard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”), The Bank of New York Mellon, as trustee, and BNY Mellon Trust of Delaware (successor to The Bank of New York (Delaware)), as co-trustee. Standard Oil and BP Alaska are indirect wholly-owned subsidiaries of BP p.l.c. (“BP”). On December 15, 2010, The Bank of New York Mellon resigned as trustee and was replaced by The Bank of New York Mellon Trust Company, N.A., a national banking association, as successor trustee (the “Trustee”).

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 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 interests as of February 28, 1989 in the Prudhoe Bay field situated on the North Slope of Alaska (the “1989 Working Interests”). Trust Unit holders are subject 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 Mellon Trust Company, N.A. and BNY Mellon Trust of Delaware, a Delaware banking corporation. BNY Mellon Trust of Delaware serves as co-trustee in order to satisfy certain requirements of the Delaware Statutory Trust Act. The Bank of New York Mellon Trust Company, N.A. alone is able to exercise the rights and powers granted to the Trustee in the Trust Agreement.

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

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

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BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a Modified Basis of Cash Receipts and Disbursements)

September 30, 2012

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 (i) upon a vote of 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 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 that 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.

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:

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. These modified cash basis financial statements are unaudited but, in the opinion of the Trustee, include all adjustments necessary to present fairly the assets, liabilities and corpus of the Trust as of September 30, 2012 and December 31, 2011, and the modified cash basis of earnings and distributions and changes in Trust corpus for the three and nine-month periods ended September 30, 2012 and 2011. 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, 2012 and December 31, 2011, cash equivalents which represent the cash reserve consist of U.S. Treasury bills with an initial term of less than three months.

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BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a Modified Basis of Cash Receipts and Disbursements)

September 30, 2012

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.

These unaudited 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, 2011. The cash earnings and distributions for the interim periods presented are not necessarily indicative of the results to be expected for the full year.

At inception in February 1989, the Royalty Interest held by the Trust had a carrying value of $535,000,000. In accordance with generally accepted accounting principles, the Trust amortized the value of the Royalty Interest based on the units of production method. Such amortization was charged directly to the Trust corpus, and did not affect cash earnings. In addition, the Trust periodically evaluated impairment of the Royalty Interest by comparing the undiscounted cash flows expected to be realized from the Royalty Interest to the carrying value, pursuant to the Financial Accounting Standards Board Accounting Standards Codification 360, Property, Plant, and Equipment. If the expected future undiscounted cash flows were less than the carrying value, the Trust recognized impairment losses for the difference between the carrying value and the estimated fair value of the Royalty Interest. By December 31, 2010, the Trust had recognized accumulated amortization of $359,473,000 and aggregate impairment write-downs of $175,527,000 reducing the carrying value of the Royalty Interest to zero.

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.

The Alaska oil and gas production tax statutes were amended by a bill (the “2006 Amendments”) which became effective in August 2006. The 2006 Amendments replaced an

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BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a Modified Basis of Cash Receipts and Disbursements)

September 30, 2012

oil production tax levied at the flat rate of 15% of the gross value at the point of production (the “wellhead” or “field” value) of taxable oil produced from a producer’s leases or properties in the State of Alaska. Under the 2006 Amendments, producers were taxed on the “production tax value of taxable oil” (gross value at the point of production for the calendar year less the 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 rate imposed by the 2006 Amendments was equal to 0.25% times the amount by which the simple average for each calendar month of the daily production tax values per barrel of the oil produced during the month exceeded $40 per barrel.

In December 2007, a bill (popularly titled “Alaska’s Fair and Equitable Share” or “ACES”) took effect which further amended the Alaska oil and gas production tax statutes in certain respects. ACES changed the basic tax rate from 22.5% to 25% and increased the progressivity rate. If the producer’s average monthly production tax value per barrel is greater than $30 but not more than $92.50, the progressivity tax rate is 0.4% times the amount by which the average monthly production tax value exceeds $30 per barrel. If the producer’s average monthly production tax value per barrel is greater than $92.50, the progressivity tax rate is the sum of 25% and the product of 0.1% multiplied by the difference between the average monthly production tax value per barrel and $92.50, except that the sum may not exceed 50%.

The Trustee and BP Alaska entered into a letter agreement in October 2006 and an amendment thereto in January 2008 (the “Letter Agreement”) to resolve issues associated with the 2006 Amendments and ACES. The Letter Agreement modified the calculation of Production Taxes in the daily Per Barrel Royalty calculation effective as of August 20, 2006, in the case of the 2006 Amendments, and effective December 20, 2007, in the case of ACES. It also provides that the retroactivity provisions of the respective tax bills are not applicable to the Per Barrel Royalty calculation for periods prior to the effective dates of the 2006 Amendments and ACES.

The royalty payments received by the Trust in January 2012 and January 2011 with respect to the quarters ended December 31, 2011 and December 31, 2010 were adjusted by BP Alaska to compensate for underpayment of the royalties due with respect to the quarters ended September 30, 2011 and September 30, 2010, respectively. Average net production of crude oil and condensate from the proved reserves allocated to the Trust was less than 90,000 barrels per day during those quarters and the royalty payments by BP Alaska with respect to those quarters were based on estimates by BP Alaska of production levels because actual data was not available by the date on which payments were required to be made to the Trust.

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BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a Modified Basis of Cash Receipts and Disbursements)

September 30, 2012

Subsequent recalculation by BP Alaska of the royalty payments due based on actual production data resulted in the payment adjustments shown in the table below (in thousands):

On October 15, 2012 the Trust received a cash distribution of approximately $39,174,000 from BP Alaska. This payment consisted of $38,987,000 representing the royalty payment due with respect to the Trust’s Royalty Interest for the quarter ended September 30, 2012, plus $187,000 representing the amount of an underpayment by BP Alaska, including interest on the underpayment of the royalty payment due with respect to the quarter ended June 30, 2012. On October 19, 2012, after adding interest received with respect to the cash reserve fund and deducting Trust administrative expenses, the Trustee distributed approximately $38,982,000 (approximately $1.82 per Unit) to Unit holders of record on October 15, 2012.

Production levels from the 1989 Working Interests for the quarter ended September 30, 2012 declined from production levels for the quarter ended June 30, 2012 due to maintenance at the Prudhoe Bay field.

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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 material risks known to the Trustee 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, 2011 (the “2011 Annual 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 2011 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 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 Part I, Item 1 of the 2011 Annual Report for a description of the calculation of the Per Barrel Royalty, and the discussion under “THE PRUDHOE BAY UNIT AND FIELD – Reserve Estimates” in Part I, Item 1 of the 2011 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. See the discussion under “THE TRUST” in Part I, Item 1 of the 2011 Annual Report.

Since 1999, the Trustee has maintained a $1,000,000 cash reserve to provide liquidity to the Trust during any future periods in which the Trust does not receive a distribution. The Trustee will draw funds from the cash reserve account during any quarter in which the quarterly distribution received by the Trust does not exceed the liabilities and expenses of the Trust, and

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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 with each quarterly distribution.

As discussed under “CERTAIN TAX CONSIDERATIONS” in Part I, Item 1 of the 2011 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 by the Trustee 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 domestic and world supply and demand and other market conditions as well as the world political situation as it affects the members of OPEC and other producing countries. The effect of changing economic and political conditions on the demand for and supply of 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 2011 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 each Quarterly Record Date from the royalty payment received. Revenues and Trust expenses presented in the statement of cash earnings and distributions are recorded on a modified cash basis and, as a result, royalty revenues and distributions shown in such statements for the three- and nine-month periods ended September 30, 2012 and 2011, respectively, are attributable to BP Alaska’s operations during the three and nine-month periods ended June 30, 2012 and 2011, respectively.

The following table summarizes the factors which determined the Per Barrel Royalties used to calculate the payments received by the Trust in January, April and July 2012 and 2011 (see Note 1 of Notes to Financial Statements (Unaudited) in Part I, Item 1). The information in the table has been furnished by BP Alaska.

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“Royalty Production” for each day in a calendar quarter is 16.4246% of the first 90,000 barrels of the actual average daily net production of oil and condensate for the quarter from the proved reserves allocated to the Trust. During periods when BP Alaska’s average daily net production from those reserves exceeds 90,000 barrels, 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. Since 2006, BP Alaska has undertaken a program of field wide infrastructure renewal, pipeline replacement and well mechanical improvements. As a consequence of these activities and the required downtime, and the natural production declines from the Prudhoe Bay field, Royalty Production from the proved reserves of oil and condensate allocated to the Trust was less than 90,000 barrels per day on an annual basis in 2010 and 2011. BP Alaska anticipates that its average net production of oil and condensate from those reserves will be below 90,000 barrels per day on an annual basis in most future years.

BP Alaska estimates Royalty Production from the reserves allocated to the Trust for purposes of calculating quarterly royalty payments to the Trust because complete actual field production data for the preceding calendar quarter generally is not available by the Quarterly Record Date. To the extent that average net production from those reserves is below 90,000 barrels per day in any quarter, recalculation by BP Alaska of actual Royalty Production data may result in revisions of prior Royalty Production estimates. Revisions by BP Alaska of its Royalty Production calculations cause BP Alaska to adjust its quarterly royalty payments to the Trust to compensate for overpayments or underpayments of royalties with respect to prior quarters. Such adjustments, if material, may adversely affect certain Unit holders who buy or sell Units between the Quarterly Record Dates for the Quarterly Distributions affected.

The Quarterly Distributions received by the Trust from BP Alaska in January 2012 and January 2011 were adjusted by BP Alaska to compensate for underpayment of royalties due to the Trust with respect to the quarters ended September 30, 2011 and September 30, 2010. See Note 6 of Notes to Financial Statements (Unaudited) in Item 1. Because the statements of cash earnings and distributions of the Trust are prepared on a modified cash basis, royalty revenues for the nine-month periods ended September 30, 2012 and 2011 reflect the amounts of the adjustments with respect to the earlier fiscal periods.

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Three Months Ended September 30, 2012 Compared to

Three Months Ended September 30, 2011

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. The first of the following two tables shows the changes from the second quarter of 2011 to the second quarter of 2012 in the factors which determined the Per Barrel Royalties used to calculate the royalty payments received during the third quarters of 2011 and 2012. The second of the two tables shows the resulting changes in the Trust’s revenues and distributions and the changes in the Trust’s expenses from the third quarter of 2011 to the third quarter of 2012.

The increase in adjusted Chargeable Costs resulted principally from the scheduled annual increase in Chargeable Costs from $16.60 in 2011 to $16.70 in 2012. The Cost Adjustment Factor increased marginally between the two periods due to low inflation. The decrease in Production Taxes reflected the decline in the average WTI Price and average net production between the two periods. The decline in average net production from the 1989 Working Interests between the two periods reflects the declining rate of production from the Prudhoe Bay field.

The period-to-period decreases in royalty revenues, cash earnings and cash distributions are due to the lower average WTI Prices and average net production that prevailed in the second quarter of 2012, compared to the second quarter of 2011. The increase in administrative expenses reflects certain increases in the overall costs of supplies and services and timing differences in accruals of expenses.

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Nine Months Ended September 30, 2012 Compared to

Nine Months Ended September 30, 2011

Trust royalty revenues received during the first nine months of the fiscal year are based on Royalty Production during the first and second quarter of the fiscal year and the fourth quarter of the preceding fiscal year. The first of the following two tables shows the changes from the nine months ended June 30, 2011 to the nine months ended June 30, 2012 in the factors which determined the Per Barrel Royalties used to calculate the royalty payments received during the nine months ended September 30 of the respective years. The second of the two tables shows the resulting changes in the Trust’s revenues and distributions and the changes in the Trust’s expenses from the first nine months of 2011 to the first nine months of 2012.

The increase in adjusted Chargeable Costs resulted principally from the scheduled annual increase in Chargeable Costs from $16.60 in 2011 to 16.70 in 2012. The Cost Adjustment Factor increased marginally between the two periods due to low inflation. As noted above, the decline in average net production from the 1989 Working Interests between the two periods reflects the declining rate of production from the Prudhoe Bay field.

The slight period-to-period increases in royalty revenues, cash earnings and cash distributions are due to the higher average WTI Prices that prevailed in the nine months ended June 30, 2012, compared to the nine months ended June 30, 2011. The average increase in WTI Prices, however, was offset by proportionately greater increases in adjusted Chargeable Costs and in Production Taxes due to the progressivity feature of the Alaska Production Tax Statutes.

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

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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.

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 listed. 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 1989 Working Interests as of December 31, 1987.

In addition, the Conveyance gives the Trust certain rights to inspect the books and records of BP Alaska and discuss the affairs, finances and accounts of BP Alaska relating to the 1989 Working Interests with representatives of BP Alaska; it also requires BP Alaska to provide the Trust with such other information as the Trustee may reasonably request from time to time and to which BP Alaska has access.

The 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

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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.

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PART II

OTHER INFORMATION

None.

There have been no material changes in risk factors disclosed in the 2011 Annual Report that are known to the Trustee.

None.

None.

(a) Reference is made to Note 7 of Notes to Financial Statements (Unaudited) in Part I, Item 1 (Form 8-K, Item 8.01).

(b) Not applicable.

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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.

Date: November 9, 2012

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

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INDEX TO EXHIBITS