ITEM 1B.
UNRESOLVED STAFF COMMENTS
The Trust has not received any written comments from the staff of the Securities and Exchange Commission regarding its periodic or current reports under the Securities Exchange Act of 1934 (the “Exchange Act”) that remain unresolved.
Reference is made to Item 1 for the information required by this item.
None
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of Unit holders during the fourth quarter ended December 31, 2009.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS
The Units are listed and traded on the New York Stock Exchange under the symbol BPT. The following table shows the high and low sales prices per Unit on the New York Stock Exchange and the cash distributions paid per Unit, for each calendar quarter in the two years ended December 31, 2009.
As of February 23, 2010, 21,400,000 Units were outstanding and were held by 577 holders of record. No Units were purchased by the Trust or any affiliated purchaser during the year ended December 31, 2009.
Future payments of cash distributions are dependent on such factors as prevailing WTI Prices, the relationship of the rate of change in the WTI Price to the rate of change in the Consumer Price Index, the Chargeable Costs, the rates of Production Taxes prevailing from time to time, and the actual Royalty Production from the 1989 Working Interests. See “THE ROYALTY INTEREST” in Item 1.
The following table presents in summary form selected financial information regarding the Trust.
ITEM 7.
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”
in Item 1 for information concerning the estimated future net revenues of the Trust. However, the Trust Agreement gives the Trustee power to borrow, establish a cash reserve, or dispose of all or part of the Trust property under limited circumstances. See the discussion under “THE TRUST - Sales of Royalty Interest; Borrowings and Reserves” in Item 1.
Since 1999, the Trustee has maintained a $1,000,000 cash reserve to provide liquidity to the Trust during any future periods in which the Trust does not receive a distribution. The Trustee will draw funds from the cash reserve account during any quarter in which the quarterly distribution received by the Trust does not exceed the liabilities and expenses of the Trust, and will replenish the reserve from future quarterly distributions, if any. The Trustee anticipates that it will keep this cash reserve program in place until termination of the Trust.
Amounts set aside for the cash reserve are invested by the Trustee in U.S. government or agency securities secured by the full faith and credit of the United States. Interest income received by the Trust from the investment of the reserve fund is added to the distributions received from BP Alaska and paid to the Unit holders on each Quarterly Record Date.
Annual decreases in Trust corpus and total assets are the result of amortization of the Royalty Interest. See Notes 2 and 3 of Notes to Financial Statements in Item 8.
Results of Operations
Relatively modest changes in oil prices significantly affect the 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.
When BP Alaska’s average net production of oil and condensate per quarter from the 1989 Working Interests exceeds 90,000 barrels a day, the principal factors affecting the 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. However, it is likely that the Trust’s revenues in future periods also will be affected by increases and decreases in production from the 1989 Working Interests. BP Alaska’s net production of oil and condensate allocated to the Trust from proved reserves was less than 90,000 barrels per day on an annual basis during 2008 and 2009. The Trustee has been advised that BP Alaska expects that average net production allocated to the Trust from the proved reserves will be less than 90,000 barrels a day on an annual basis in future years.
BP Alaska estimates Royalty Production from the 1989 Working Interests for purposes of calculating quarterly royalty payments to the Trust because complete actual field production data for the preceding calendar quarter generally is not available by the Quarterly Record Date. To the extent that average net production from the 1989 Working Interests is below 90,000 barrels per day, calculation by BP Alaska of
actual Royalty Production data may result in revisions of prior Royalty Production estimates. Revisions by BP Alaska of its Royalty Production calculations may result in quarterly royalty payments by BP Alaska which reflect adjustments for overpayments or underpayments of royalties with respect to prior quarters. Such adjustments, if material, may adversely affect certain Unit holders who buy or sell Units between the Quarterly Record Dates for the Quarterly Distributions affected. See Note 8 of Notes to Financial Statements in Item 8. Because the annual statement of cash earnings and distributions of the Trust is prepared on a modified cash basis, royalty revenues for the calendar year do not include the amounts of underpayments or overpayments affecting payments received during the fourth quarter of the year.
During the years 2008 and 2009 and the period of 2010 up to the date of this report, WTI Prices have been above the level necessary for the Trust to receive a Per Barrel Royalty. Whether the Trust will be entitled to future distributions during the remainder of 2010 will depend on WTI Prices prevailing during the remainder of the year.
In June 2009, the Financial Accounting Standards Board (“FASB”) issued a new accounting standard, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” This new accounting standard established the “FASB Accounting Standards Codification,” or FASB ASC, as the source of authoritative generally accepted accounting principles (“GAAP”) recognized by the FASB for non-governmental entities. All existing accounting standards have been superseded and accounting literature not included in the FASB ASC is considered non-authoritative. Adoption of the FASB ASC did not effect significant changes in GAAP and had no effect on the reporting of Trust’s financial condition or results of operations.
2009 compared to 2008
WTI Prices fell precipitously during the fourth quarter of 2008, from an average of approximately $104 per barrel during September 2008 to an average of approximately $41 per barrel during December 2008. WTI Prices then rose gradually during the first three quarters of 2009, reaching a high average monthly price of approximately $71 during August 2009. Average WTI Prices for the twelve months ended September 30, 2009 were 47% lower than during the preceding twelve-month period, which resulted in royalty revenues that were 49% lower during the twelve months ended December 31, 2009 than during the twelve months ended December 31, 2008. Cash earnings during 2009 declined only 37% from 2008, however, as a result of the receipt by the Trust during December 2009 of a $29,474,000 payment from BP Alaska in settlement of certain claims that arose from the 2006 partial shutdown of the Prudhoe Bay Unit. Production Taxes charged against the Per Barrel Royalty during the twelve months ended September 30, 2009 declined approximately 73% from the preceding twelve-month period as a result of the progressivity feature of the 2007 ACES amendments to the Alaska oil and gas tax statutes (see “THE ROYALTY INTEREST - Production Taxes” in Item 1). Trust administrative expenses declined approximately 19% during the year ended December 31, 2009, principally due to declining legal fees and expenses.
2008 compared to 2007
WTI Prices rose rapidly during the fourth quarter of 2007 and throughout the first half of 2008, reaching a high of over $145 per barrel early in July 2008 before receding to an average of approximately $104 per barrel during September 2008. As a result of the increases in WTI Prices, average WTI Prices for the twelve months ended September 30, 2008 were 67% higher than during the preceding twelve-month period. Royalty revenues and cash earnings rose 42% and 43%, respectively, during the twelve months ended December 31, 2008 compared to the twelve months ended December 31, 2007, but the
higher tax rates imposed by ACES, imposed a significant burden on Per Barrel Royalties. Production taxes charged against the average Per Barrel Royalty were approximately 264% higher with respect to the twelve months ended September 30, 2008 than during the twelve months ended September 30, 2007. Trust administrative expenses for 2008 rose 6.5% from 2007, principally due to legal fees and expenses related litigation and other issues arising from the 2006 shutdown of the Prudhoe Bay field.
ITEM 7A.
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.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BP PRUDHOE BAY ROYALTY TRUST
Report of Independent Registered Public Accounting Firm
Trustee and Holders of Trust Units of
BP Prudhoe Bay Royalty Trust:
We have audited the accompanying statements of assets, liabilities, and trust corpus of BP Prudhoe Bay Royalty Trust (the Trust) as of December 31, 2009 and 2008, and the related statements of cash earnings and distributions and changes in trust corpus for each of the years in the three year period ended December 31, 2009. These financial statements are the responsibility of The Bank of New York Mellon (formerly named The Bank of New York), as the 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of the Trust as of December 31, 2009 and 2008 and its cash earnings and distributions and changes in trust corpus for each of the years in the three year period ended December 31, 2009 in conformity with the modified cash basis of accounting described in note 2.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2010 expressed an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 1, 2010
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)
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)
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)
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, 2009
(1)
Formation of the Trust and Organization
BP Prudhoe Bay Royalty Trust (the “Trust”), a grantor trust, was created as a Delaware statutory trust pursuant to a Trust Agreement dated February 28, 1989 among the Standard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”), The Bank of New York Mellon (the “Trustee”) and BNY Mellon Trust of Delaware (successor to The Bank of New York (Delaware)), as co-trustee. Standard Oil and BP Alaska are indirect wholly owned subsidiaries of BP p.l.c. (“BP”).
On February 28, 1989, Standard Oil conveyed an overriding royalty interest (the “Royalty Interest”) to the Trust. The Trust was formed for the sole purpose of owning and administering the Royalty Interest. The Royalty Interest represents the right to receive, effective February 28, 1989, a per barrel royalty (the “Per Barrel Royalty”) of 16.4246% on the lesser of (a) the first 90,000 barrels of the average actual daily net production of oil and condensate per quarter or (b) the average actual daily net production of oil and condensate per quarter from BP Alaska’s working interest as of February 28, 1989 in the Prudhoe Bay field, located on the North Slope of Alaska. Trust Unit holders will remain subject at all times to the risk that production will be interrupted or discontinued. BP has guaranteed the performance of BP Alaska of its payment obligations with respect to the Royalty Interest.
Effective January 1, 2000, BP Alaska and all other Prudhoe Bay working interest owners cross-assigned interests in the Prudhoe Bay field pursuant to the Prudhoe Bay Unit Alignment Agreement. BP Alaska retained all rights, obligations, and liabilities associated with the Trust.
The trustees of the Trust are The Bank of New York Mellon, a New York banking corporation, and BNY Mellon Trust of Delaware, a Delaware banking corporation. BNY Mellon Trust of Delaware serves as co-trustee in order to satisfy certain requirements of the Delaware Statutory Trust Act. The Bank of New York Mellon alone is able to exercise the rights and powers granted to the Trustee in the Trust Agreement.
The Per Barrel Royalty in effect for any day is equal to the price of West Texas Intermediate crude oil (the “WTI Price”) for that day less scheduled Chargeable Costs (adjusted for inflation) and Production Taxes (based on statutory rates then in existence).
The Trust is passive, with the Trustee having only such powers as are necessary for the collection and distribution of revenues, the payment of Trust liabilities, and the protection of the Royalty Interest. The Trustee, subject to certain conditions, is obligated to establish cash reserves and borrow funds to pay liabilities of the Trust when they become due. The Trustee may sell Trust properties only (a) as authorized by a vote of the Trust unit holders, (b) when necessary to provide for the payment of specific liabilities of the Trust then due (subject to certain conditions) or (c) upon termination of the Trust. Each Trust Unit issued and outstanding represents an equal undivided share of beneficial interest in the Trust. Royalty payments are received by the Trust and distributed to Trust Unit holders, net of Trust expenses, in the month succeeding the end of each calendar quarter. The Trust will terminate upon the first to occur of the following events:
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
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, 2009, 2008 and 2007 was $0.38, $0.38 and $0.38, respectively. The Trust evaluates impairment of the Royalty Interest by comparing the undiscounted cash flows expected to be realized from the Royalty Interest to the carrying value, pursuant to the Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) 360, Property, Plant, and Equipment. If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the Royalty Interest.
While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful because quarterly distributions to the Trust unit holders are based on net cash receipts. The accompanying modified cash basis financial statements contain all adjustments necessary to present fairly the assets, liabilities and corpus of the Trust as of December 31, 2009 and 2008, and the modified cash earning and distributions and changes in Trust corpus for the years ended December 31, 2009, 2008 and 2007. The adjustments are of a normal recurring nature and are, in the opinion of the Trustee, necessary to fairly present the results of operations.
As of December 31, 2009 and 2008, cash equivalents which represent the cash reserve consist of U.S. treasury bills with an initial term of less than three months.
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
Estimates and assumptions are required to be made regarding assets, liabilities and changes in Trust corpus resulting from operations when financial statements are prepared. Changes in the economic environment, financial markets and any other parameters used in determining these estimates could cause actual results to differ, and the difference could be material.
(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)
Alaska Oil and Gas Production Tax
The Alaska oil and gas production tax statutes were amended by a bill (the “2006 Amendments”) which became effective in August 2006. The 2006 Amendments replaced an oil production tax levied at the flat rate of 15% of the gross value at the point of production (the “wellhead” or “field” value) of taxable oil produced from a 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.
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
(8)
Royalty Revenue Adjustments
Certain of the royalty payments received by the Trust in 2009, 2008 and 2007 were adjusted by BP Alaska to compensate for underpayments or overpayments of the royalties due with respect to the quarters ended prior to the dates of such payments. Average net production of crude oil and condensate from the proved reserves allocated to the Trust was less than 90,000 barrels per day during certain quarters. Royalty payments by BP Alaska with respect to those quarters were based on estimates by BP Alaska of production levels because actual data was not available by the dates on which payments were required to be made to the Trust. Subsequent recalculation by BP Alaska of royalty payments due based on actual production data resulted in the payment adjustments shown in the table below (in thousands):
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
(10)
Summary of Quarterly Results (Unaudited)
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
(11)
Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Reserves (Unaudited)
Pursuant to Statement of FASB ASC 932, Extractive Activities - Oil and Gas, the Trust is required to include in its financial statements supplementary information regarding estimates of quantities of proved reserves attributable to the Trust and future net cash flows. The following information in this note with respect to the year ended December 31, 2009 reflects the adoption of Securities Exchange Act Release No. 59192, Modernization of Oil and Gas Reporting which became effective for financial statements for fiscal years ending on or after December 31, 2009. The Trust has not restated reserve information with respect to the years ended December 31, 2007 and 2008 to reflect changes in the methodology for determining proved reserves prescribed by Release No. 59192.
Estimates of proved reserves are inherently imprecise and subjective and are revised over time as additional data becomes available. Such revisions may often be substantial. Information regarding estimates of proved reserves attributable to the combined interests of BP Alaska and the Trust were based on reserve estimates prepared by BP Alaska. BP 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 Prudhoe Bay field. Reserve volumes attributable to the Trust were estimated by allocating to the Trust its share of estimated future production from the field, based on the 12-month average WTI Price for 2009 ($61.18 per barrel), and on the WTI Price on December 31, 2008 ($44.60 per barrel) and December 31, 2007 ($96.01 per barrel). Because the reserve volumes attributable to the Trust are estimated using an allocation of reserve volumes based on the estimated future production and on the current WTI Price, a change in the timing of estimated production or a change in the WTI price will result in a change in the 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, 2009, 2008 and 2007, based on BP Alaska’s latest reserve estimate at such time and the 12-month average WTI price for 2009 and WTI Prices on December 31, 2008 and 2007, were estimated to be 68, 55 and 98 million barrels, respectively (of which 57, 46 and 87 million barrels, respectively, are proved developed reserves). Under the provisions of FASB ASC 932, no consideration can be given to reserves not considered proved at the present time.
The standardized measure of discounted future net cash flow relating to proved reserves disclosure required by FASB ASC 932 assigns monetary amounts to proved reserves based on current prices. This discounted future net cash flow should not be construed as the current market value of the Royalty Interest. A market valuation determination would include, among other things, anticipated price changes and the value of additional reserves not considered proved at the present time or reserves that may be produced after the currently anticipated end of field life. At December 31, 2009, 2008 and 2007, the standardized measure of discounted future net cash flow relating to proved reserves attributable to the Trust (estimated in accordance with the provisions of FASB ASC 932),
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
(a)
The following are the principal sources of the change in the standardized measure of discounted future net cash flows (in thousands):
BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2009
The changes in estimated quantities of proved oil and condensate were as follows:
Proved developed and undeveloped reserves (thousands of barrels) as of:
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There have been no changes in accountants and no disagreements with accountants on any matter of accounting principles or practices or financial statement disclosures during the two fiscal years ended December 31, 2009.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
The Trustee has disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Exchange Act) that are designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the 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 and the assumptions utilized in arriving at the estimates contained in the report.
In addition, the Conveyance gives the Trust and its independent accountants certain rights to inspect the books and records of BP Alaska and discuss the affairs, finances and accounts of BP Alaska relating to the 1989 Working Interests with representatives of BP Alaska; it also requires BP Alaska to provide the Trust with such other information as the Trustee may reasonably request from time to time and to which BP Alaska has access.
The 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 2009, 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 Mellon, as Trustee of the Trust, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the 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, 2009.
The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2009 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report set forth in full below.
Report of Independent Registered Public Accounting Firm
Trustee and Holders of Trust Units of
BP Prudhoe Bay Royalty Trust:
We have audited BP Prudhoe Bay Royalty Trust’s (the Trust) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Bank of New York Mellon (formerly named The Bank of New York), as the Trust’s trustee (the Trustee), is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
The 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. The 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, BP Prudhoe Bay Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities, and trust corpus of BP Prudhoe Bay Royalty Trust as of December 31, 2009 and 2008, and the related statements of cash earnings and distributions and changes in trust corpus for each of the years in the three year period ended December 31, 2009, and our report dated March 1, 2010 expressed an unqualified opinion on those financial statements.
KPMG LLP
Dallas, Texas
March 1, 2010
Changes in Internal Control Over Financial Reporting. There has not been any change in the 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.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The Trust has no directors or executive officers. The Trust is administered by the Trustee under the authority granted it in the Trust Agreement. The Trust Agreement grants the Trustee only the rights and powers necessary to achieve the purposes of the Trust. See “THE TRUST - Duties and Powers of Trustee” in Item 1.
The Trustee may be removed with or without cause by vote of holders of a majority of the Units at a meeting called and held as provided in the Trust Agreement. At the meeting the Unit holders may appoint a successor trustee meeting the requirements set forth in the Trust Agreement. See “THE TRUST - Resignation or Removal of Trustee” in Item 1.
The Trust has not adopted a code of ethics. The standards of conduct governing the Trustee are set forth in the Trust Agreement and Delaware law. Ethical standards applicable to the employees of the Trustee are set forth in the Code of Conduct which may be found at http://www.bnymellon.com/ethics.
There is no audit committee or committee performing comparable functions responsible for reviewing the audited financial statements of the Trust.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The Trust has no directors, officers or employees to whom it pays compensation. The Trust is administered by employees of the Trustee in the ordinary course of their employment who receive no compensation specifically related to their services to the Trust.
Under the Trust Agreement, the Trustee is entitled to receive on each Quarterly Record Date a quarterly fee, currently consisting of: (i) a quarterly administrative fee of $.0017 per Unit outstanding on the Quarterly Record Date plus $10.00 for each payment by wire transfer to a Unit holder and (ii) a transfer service fee of $2.42 per Unit holder account as of the Quarterly Record Date. Both the administrative service fee and the transfer service fee are subject to increase in each calendar year by the proportionate increase, if any, during the preceding calendar year in the Consumer Price Index (as defined in the Conveyance; see “THE ROYALTY INTEREST - Cost Adjustment Factor” in Item 1) during the preceding calendar year. The Trustee also bills the Trust for certain reimbursable expenses. There is no compensation committee or committee performing similar functions with authority to determine any compensation of the Trustee other than the fees and reimbursable expenses provided for in the Trust Agreement.
The compensation received by the Trustee from the Trust during the three fiscal years ended December 31, 2009 was as follows:
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Securities Authorized for Issuance under Equity Compensation Plans
No Units are authorized for issuance under any form of equity compensation plan.
Unit Ownership of Certain Beneficial Owners
As of February 26, 2010, there were no persons known to the Trustee to be the beneficial owners of more than five percent of the Units.
Unit Ownership of Management
Neither BP Alaska, Standard Oil, nor BP owns any Units. No Units are owned by The Bank of New York Mellon, as Trustee or in its individual capacity, or by BNY Mellon Trust of Delaware), as co-trustee or in its individual capacity.
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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
There has been no transaction by the Trust since the beginning of 2009, or any currently proposed transaction in which a related person (as defined in Item 404 of Regulation S-K) had or will have a direct or indirect material interest, except for payment to the Trustee of the fees and reimbursement for expenses prescribed in the Trust Agreement. See Item 11 above.
The Trust has no independent directors. See Item 10 above.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees for services performed by KPMG LLP for the years ended December 31, 2009 and 2008 are:
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.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) FINANCIAL STATEMENTS
The following financial statements of the Trust are included in Part II, Item 8:
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2009 and 2008
Statements of Cash Earnings and Distributions for the years ended December 31, 2009, 2008 and 2007
Statements of Changes in Trust Corpus for the years ended December 31, 2009, 2008 and 2007
Notes to Financial Statements
(b) FINANCIAL STATEMENT SCHEDULES
All financial statement schedules have been omitted because they are either not applicable, not required or the information is set forth in the financial statements or notes thereto.
(c) EXHIBITS
4.1
BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New York Trustee, and F. James Hutchinson, Co-Trustee.
4.2
Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc. and The Standard Oil Company.
4.3
Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay Royalty Trust.
4.4
Support Agreement dated as of February 28, 1989, as amended May 8, 1989, among The British Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.
4.5
Letter agreement executed October 13, 2006 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee.
4.6
Letter agreement executed January 11, 2008 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee.
10.1
Settlement Agreement, dated May 8, 2009, among BP Exploration (Alaska) Inc., The Bank of New York Mellon, as Trustee, and BNY Mellon Trust Company of Delaware, as Co-Trustee.
Rule 13a-14(a) certification.
Section 1350 certification.
Report of Miller and Lents, Ltd., dated February 19, 2010.
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.
March 1, 2010
The Registrant is a trust and has no officers, directors, or persons performing similar functions. No additional signatures are available and none have been provided.
INDEX TO EXHIBITS