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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K
 þ
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the Fiscal Year ended December 31, 2005
 OR
 o
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 Commission File Number 1-10243
 BP PRUDHOE BAY ROYALTY TRUST
  DELAWAREState or other jurisdiction
    
    13-6943724of incorporation or organization)
    
    (I.R.S. Employer Identification No.)
 THE BANK OF NEW YORK, TRUSTEE101 BARCLAY STREETNEW YORK, NEW YORK
    
    10286(Address of principal executive offices)
    
    (Zip Code)
   Title of Each Class
    
    Name of Each Exchange on Which RegisteredUNITS OF BENEFICIAL INTEREST
    
    NEW YORK STOCK EXCHANGE
  þ o
 o þ
 þ o
 þ
  þ o o
 o þ
   DOCUMENTS INCORPORATED BY REFERENCE




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##### Table of Contents



TABLE OF CONTENTS
 PART I
    
    
    1ITEM 1. BUSINESS
    
    
    1INTRODUCTION
    
    
    1THE TRUST
    
    
    1THE ROYALTY INTEREST
    
    
    6THE UNITS
    
    
    8THE BP SUPPORT AGREEMENT
    
    
    10THE PRUDHOE BAY UNIT AND FIELD
    
    
    11INDEPENDENT OIL AND GAS CONSULTANTS REPORT
    
    
    16INDUSTRY CONDITIONS AND REGULATIONS
    
    
    21CERTAIN TAX CONSIDERATIONS
    
    
    21ITEM 2. PROPERTIES
    
    
    23ITEM 1A. RISK FACTORS
    
    
    23ITEM 1B. UNRESOLVED STAFF COMMENTS
    
    
    26ITEM 3. LEGAL PROCEEDINGS
    
    
    26ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
    
    
    26PART II
    
    
    26ITEM 5. MARKET FOR REGISTRANTS UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS
    
    
    26ITEM 6. SELECTED FINANCIAL DATA
    
    
    27ITEM 7. TRUSTEES DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
    
    
    27ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
    
    
    29ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
    
    
    30ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
    
    
    42ITEM 9A. CONTROLS AND PROCEDURES
    
    
    42ITEM 9B. OTHER INFORMATION
    
    
    44
 i




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PART III
    
    
    44ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
    
    
    44ITEM 11. EXECUTIVE COMPENSATION
    
    
    45ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
    
    
    45ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
    
    
    45ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
    
    
    46ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
    
    
    46SIGNATURES
    
    
    48EX-31 CertificationEX-32
 ii




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##### Table of Contents



PART I
 
 ITEM 1. BUSINESS
 
 INTRODUCTION
  http://www.sec.gov.
 rreale@bankofny.com
  Forward-Looking Statements




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##### Table of Contents



THE TRUST
 Trust Property
 *
  Employees
  Duties and Powers of the Trustee
   
 *
    
    The term barrel is a unit of
measure of petroleum liquids equal to 42 United States gallons corrected to 60
degrees Fahrenheit temperature. 2




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Sales of Assets, Borrowings and Reserves
      3




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Amendment of the Trust Agreement
  Resignation or Removal of Trustee
  Termination of the Trust
  4




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Voting Rights of Unit Holders
   5




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##### Table of Contents



THE ROYALTY INTEREST
  Royalty Production
  Per Barrel Royalty
  WTI Price
  Chargeable Costs
  6




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Calendar
    
    Chargeable Costs
    
    Calendar
    
    Chargeable Costsyear
    
    per barrel
    
    year
    
    per barrel2006
    
    $
    12.50
    
    
    
    2014
    
    
    $
    16.902007
    
    
    12.75
    
    
    
    2015
    
    
    
    17.002008
    
    
    13.00
    
    
    
    2016
    
    
    
    17.102009
    
    
    13.25
    
    
    
    2017
    
    
    
    17.202010
    
    
    14.50
    
    
    
    2018
    
    
    
    20.002011
    
    
    16.60
    
    
    
    2019
    
    
    
    23.752012
    
    
    16.70
    
    
    
    2020
    
    
    
    26.502013
    
    
    16.80
  Cost Adjustment Factor
  Production Taxes
  7




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Per Barrel Royalty Calculations
  Cost
    
    AdjustedAverage
    
    Chargeable
    
    Adjustment
    
    Chargeable
    
    Production
    
    Per BarrelWTI Price
    
    Costs
    
    Factor
    
    Costs
    
    Taxes
    
    Royalty2001:1st Qtr
    
    $
    28.83
    
    
    $
    10.75
    
    
    
    1.354
    
    
    $
    14.55
    
    
    $
    3.44
    
    
    $
    10.842nd Qtr
    
    
    27.92
    
    
    
    10.75
    
    
    
    1.368
    
    
    
    14.71
    
    
    
    3.29
    
    
    
    9.923rd Qtr
    
    
    26.82
    
    
    
    10.75
    
    
    
    1.367
    
    
    
    14.69
    
    
    
    3.13
    
    
    
    9.004th Qtr
    
    
    20.41
    
    
    
    10.75
    
    
    
    1.366
    
    
    
    14.68
    
    
    
    2.17
    
    
    
    3.562002:1st Qtr
    
    
    21.67
    
    
    
    11.25
    
    
    
    1.369
    
    
    
    15.40
    
    
    
    2.36
    
    
    
    3.912nd Qtr
    
    
    26.28
    
    
    
    11.25
    
    
    
    1.384
    
    
    
    15.57
    
    
    
    3.04
    
    
    
    7.673rd Qtr
    
    
    28.33
    
    
    
    11.25
    
    
    
    1.391
    
    
    
    15.65
    
    
    
    3.34
    
    
    
    9.344th Qtr
    
    
    28.25
    
    
    
    11.25
    
    
    
    1.396
    
    
    
    15.70
    
    
    
    3.33
    
    
    
    9.222003:1st Qtr
    
    
    34.08
    
    
    
    11.75
    
    
    
    1.410
    
    
    
    16.57
    
    
    
    4.19
    
    
    
    13.322nd Qtr
    
    
    29.07
    
    
    
    11.75
    
    
    
    1.413
    
    
    
    16.60
    
    
    
    3.44
    
    
    
    9.033rd Qtr
    
    
    30.30
    
    
    
    11.75
    
    
    
    1.421
    
    
    
    16.70
    
    
    
    3.62
    
    
    
    9.984th Qtr
    
    
    31.23
    
    
    
    11.75
    
    
    
    1.421
    
    
    
    16.69
    
    
    
    3.76
    
    
    
    10.782004:1st Qtr
    
    
    35.18
    
    
    
    12.00
    
    
    
    1.434
    
    
    
    17.20
    
    
    
    4.34
    
    
    
    13.642nd Qtr
    
    
    38.31
    
    
    
    12.00
    
    
    
    1.456
    
    
    
    17.47
    
    
    
    4.79
    
    
    
    16.053rd Qtr
    
    
    43.78
    
    
    
    12.00
    
    
    
    1.459
    
    
    
    17.51
    
    
    
    5.61
    
    
    
    20.664th Qtr
    
    
    48.35
    
    
    
    12.00
    
    
    
    1.471
    
    
    
    17.65
    
    
    
    6.29
    
    
    
    24.412005:1st Qtr
    
    
    49.70
    
    
    
    12.25
    
    
    
    1.477
    
    
    
    18.09
    
    
    
    6.49
    
    
    
    25.122nd Qtr
    
    
    53.09
    
    
    
    12.25
    
    
    
    1.497
    
    
    
    18.34
    
    
    
    6.98
    
    
    
    27.773rd Qtr
    
    
    63.03
    
    
    
    12.25
    
    
    
    1.512
    
    
    
    18.53
    
    
    
    8.46
    
    
    
    36.044th Qtr
    
    
    60.01
    
    
    
    12.25
    
    
    
    1.521
    
    
    
    18.63
    
    
    
    8.01
    
    
    
    33.37
 
 THE UNITS
 Units
  8




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Distributions of Income
   Reports to Unit Holders
  Limited Liability of Unit Holders
  Possible Divestiture of Units
  9




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Issuance of Additional Units
  
 THE BP SUPPORT AGREEMENT
     10




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THE PRUDHOE BAY UNIT AND FIELD
 Prudhoe Bay Unit Operation and Ownership
     Oil rim
    
    Gas capBP Alaska
    
    
    26.35
    %(a)
    
    
    26.35
    %(b)Exxon Mobil
    
    
    36.40
    
    
    
    36.40ConocoPhillips
    
    
    36.07
    
    
    
    36.07Others
    
    
    1.18
    
    
    
    1.18Total
    
    
    100.00
    %
    
    
    100.00
    %
 
 (a)
    
    The Trusts share of oil production is computed based on BP Alaskas ownership interest
in the oil rim participating area of 50.68 percent as of February 28, 1989. Subsequent
decreases in BP Alaskas participation in oil rim ownership do not affect calculation of
Royalty Production from the BP Working Interests and have not decreased the Trusts Royalty
Interest.(b)
    
    The Trusts share of condensate production is computed based on BP Alaskas ownership
interest in the gas cap participating area of 13.84 percent as of February 28, 1989.
Subsequent increases in BP Alaskas gas cap ownership do not affect calculation of Royalty
Production from the BP Working Interests and have not increased the Trusts Royalty
Interest.  11




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The Prudhoe Bay Field
  Field Geology
    Oil Characteristics
  12




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Historical Production
   Oil
    
    CondensateNet to BP
    
    
    
    
    
    Net to BPCalendar
    
    
    
    
    
    Working
    
    
    
    
    
    Workingyear
    
    Total field
    
    Interests
    
    Total field
    
    Interests(thousand barrels per day)2001
    
    
    324.9
    
    
    
    144.1
    
    
    
    131.2
    
    
    
    15.92002
    
    
    293.8
    
    
    
    130.3
    
    
    
    121.5
    
    
    
    14.72003
    
    
    273.2
    
    
    
    121.2
    
    
    
    113.8
    
    
    
    13.82004
    
    
    243.4
    
    
    
    107.9
    
    
    
    109.0
    
    
    
    13.22005
    
    
    228.9
    
    
    
    101.5
    
    
    
    96.4
    
    
    
    11.7
 Transportation of Prudhoe Bay Oil
  Reservoir Management
   13




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Reserve Estimates
     14




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Net Proved ReservesBP Working
    
    
    
    
    
    WTI PriceDecember 31
    
    Interests (a)
    
    Trust (b)
    
    per barrel(million barrels)2001
    
    
    961.7
    
    
    
    43.2
    
    
    $
    19.782002
    
    
    908.7
    
    
    
    85.8
    
    
    
    31.232003
    
    
    858.7
    
    
    
    77.9
    
    
    
    32.552004
    
    
    941.4
    
    
    
    77.4
    
    
    
    43.462005
    
    
    1,043.0
    
    
    
    85.3
    
    
    
    61.04
 
 (a)
    
    Includes proved undeveloped reserves of 112.5 million barrels at December 31, 2001; 5.5
million barrels at December 31, 2002; 139.9 million barrels at December 31, 2003; 115.4
million barrels at December 31, 2004; and 73.0 million barrels at December 31, 2005.(b)
    
    Includes proved undeveloped reserves of 0.03 million barrels at December 31, 2002; 11.0
million barrels at December 31, 2003; 9.1 million barrels at December 31, 2004; and 12.3
million barrels at December 31, 2005. No proved undeveloped reserves were attributable to
the Trust at December 31, 2001.    15




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INDEPENDENT OIL AND GAS CONSULTANTS REPORT
 
  
 Re:
    
    Estimates of Proved Reserves,Future Production Rates, andFuture Net Revenues for theBP Prudhoe Bay Royalty TrustAs of December 31, 2005
    16




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Miller and Lents, Ltd.
 The Bank of New York
    
    February 6, 2006Trustee, BP Prudhoe Bay Royalty Trust
     1.
    
    A large body of basic data and detailed analyses are available and were used in
making the estimates. In our judgment, the quantity and quality of currently available
data on reservoir boundaries, original fluid contacts, and reservoir rock and fluid
properties are sufficient to indicate that any future revisions to the estimates of
total original in-place volumes should be minor. Furthermore, the data and analyses on
recovery factors and future production rates are sufficient to support the Proved
Reserves estimates.2.
    
    The methods and procedures employed to accumulate and evaluate the necessary
information and to estimate, document, and reconcile reserves, annual production rate
forecasts, and future net revenues are effective and are in accordance with generally
accepted geological and engineering practice in the petroleum industry.3.
    
    Based on our limited independent tests of the computations of reserves,
production flowstreams, and future net revenues, such computations were performed in
accordance with the methods and procedures described to us.4.
    
    The estimated net remaining Proved Reserves attributable to the BP Prudhoe Bay
Royalty Trust as of December 31, 2005, of 85.31 million barrels of oil and condensate
are, in the aggregate, reasonable. Of the 85.31 million barrels of total Proved
Reserves, 73.03
million barrels are Proved Developed Reserves, and 12.28 million barrels are Proved
Undeveloped Reserves.5.
    
    Utilizing the specified procedures outlined in Financial Accounting Standards
Board Statement of Financial Accounting Standards No. 69, BP Exploration (Alaska) Inc.
calculated that as of December 31, 2005 production of the Proved Reserves will result
in
 17




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Miller and Lents, Ltd.
 The Bank of New York
    
    February 6, 2006Trustee, BP Prudhoe Bay Royalty Trust
 Estimated Future Net Revenues of $2,095.2 million and Present Value of Estimated
Future Net Revenues of $1,209.7 million to the BP Prudhoe Bay Royalty Trust. These
estimates are reasonable.6.
    
    BP Exploration (Alaska) Inc. estimated that as of December 31, 2005, 1,085.0
million barrels of Proved Reserves have been added to Current Reserves. This estimate
is reasonable. Current Reserves are defined in the Overriding Royalty Conveyance as net
Proved Reserves of 2,035.6 million barrels as of December 31, 1987. Net additions to
Proved Reserves after December 31, 1987 affect the Chargeable Costs that are used to
calculate the Per Barrel Royalty paid to the BP Prudhoe Bay Royalty Trust.7.
    
    The BP Exploration (Alaska) Inc. projection that its net production of oil and
condensate from Proved Reserves will continue at an average rate exceeding 90,000
barrels per day until the year 2012 is reasonable. As long as the Per Barrel Royalty
has a positive value, average daily production attributable to the BP Prudhoe Bay
Royalty Trust will remain constant until the net production falls below 90,000 barrels
per day; thereafter, production attributable to the BP Prudhoe Bay Royalty Trust will
decline with the BP Exploration (Alaska) Inc. production. However, the Per Barrel
Royalty will not have a positive value if the West Texas Intermediate Price is less
than the sum of the per barrel Chargeable Costs and per barrel Production Taxes,
appropriately adjusted in accordance with the Overriding Royalty Conveyance. Under such
circumstances, average daily production attributable to the BP Prudhoe Bay Royalty
Trust will have no value and therefore will not contribute to the reserves regardless
of BP Exploration (Alaska) Inc.s net production level.8.
    
    Based on the West Texas Intermediate Price of $61.04 per barrel on December 31,
2005, current Production Taxes, and the Chargeable Costs adjusted as prescribed by the
Overriding Royalty Conveyance, the projection that royalty payments will continue
through the year 2023 is reasonable. BP Exploration (Alaska) Inc. expects continued
economic production at a declining rate through the year 2065; however, for the
economic conditions and production forecast as of December 31, 2005 the Per Barrel
Royalty will be zero following the year 2023. Therefore, no reserves are currently
attributed to the BP Prudhoe Bay Royalty Trust after that date.9.
    
    Even if expected reservoir performance does not change, the estimated reserves,
economic life, and future revenues attributable to the BP Prudhoe Bay Royalty Trust may
change significantly in the future. This may result from changes in the West Texas
Intermediate Price or from changes in other prescribed variables utilized in
calculations defined by the Overriding Royalty Conveyance.
  18




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Miller and Lents, Ltd.
 The Bank of New York
    
    February 6, 2006Trustee, BP Prudhoe Bay Royalty Trust
         19




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Miller and Lents, Ltd.
 The Bank of New York
    
    February 6, 2006Trustee, BP Prudhoe Bay Royalty Trust
  Very truly yours,MILLER AND LENTS, LTD.By
    
    /s/ William P. Koza, P.E.

William P. Koza, P.E.
    
    [SEAL]Vice President
  20




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INDUSTRY CONDITIONS AND REGULATIONS
   
 CERTAIN TAX CONSIDERATIONS
   Federal Income Tax
 Classification of the Trust
  General Features of Grantor Trust Taxation
  Taxation of Unit Holders
  21




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Depletion Deductions
   Taxation of Foreign Unit Holders
   22




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Sale of Units
  Backup Withholding
  State Income Taxes
  
 ITEM 2. PROPERTIES
  
 ITEM 1A. RISK FACTORS
  
    
    Royalty Production from the Prudhoe Bay field is projected to decline after 2012 and
will eventually cease.
  23




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
    
    Construction of a proposed gas pipeline from the North Slope of Alaska to the Midwestern
United States could accelerate the decline in net royalty production from the Prudhoe Bay
field, result in higher production tax deductions from royalty payments to the Trust, or
both.
     
    
    Royalty payments by BP Alaska to the Trust are unpredictable, because they depend
directly on world crude oil prices which have been volatile in recent years.
  24




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
    
    Production from the Prudhoe Bay field could be interrupted by damage to the Trans-Alaska
Pipeline System from natural disasters, accidents, or deliberate attacks.
  
    
    Production from the Prudhoe Bay Unit may be interrupted or discontinued by BP Alaska.
  
    
    There are potential conflicts of interest between BP Alaska and the Trust that could
affect the royalties paid to Unit holders.
  25




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ITEM 1B. UNRESOLVED STAFF COMMENTS
  
 ITEM 3. LEGAL PROCEEDINGS
  
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  
 PART II
 
 ITEM 5. MARKET FOR REGISTRANTS UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF
UNITS
  DistributionsHigh
    
    Low
    
    Per Unit2004:First Quarter
    
    $
    30.25
    
    
    $
    22.50
    
    
    $
    0.670Second Quarter
    
    
    32.90
    
    
    
    26.31
    
    
    
    0.846Third Quarter
    
    
    40.00
    
    
    
    32.13
    
    
    
    0.998Fourth Quarter
    
    
    50.50
    
    
    
    39.95
    
    
    
    1.3042005:First Quarter
    
    $
    70.95
    
    
    $
    46.40
    
    
    $
    1.544Second Quarter
    
    
    75.79
    
    
    
    56.47
    
    
    
    1.545Third Quarter
    
    
    79.99
    
    
    
    69.50
    
    
    
    1.728Fourth Quarter
    
    
    79.90
    
    
    
    60.10
    
    
    
    2.282
   26




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ITEM 6. SELECTED FINANCIAL DATA
  Year ended December 312005
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001(in thousands, except per Unit amounts)Royalty revenues
    
    $
    152,978
    
    
    
    82,682
    
    
    
    55,986
    
    
    
    33,061
    
    
    
    59,934Interest income
    
    $
    37
    
    
    
    11
    
    
    
    10
    
    
    
    23
    
    
    
    70Trust administration expenses
    
    $
    1,097
    
    
    
    976
    
    
    
    1,168
    
    
    
    822
    
    
    
    724Cash earnings
    
    $
    151,918
    
    
    
    81,717
    
    
    
    54,828
    
    
    
    32,262
    
    
    
    59,280Cash distributions
    
    $
    151,908
    
    
    
    81,702
    
    
    
    54,867
    
    
    
    32,246
    
    
    
    59,319Cash distributions per unit
    
    $
    7.098
    
    
    
    3.818
    
    
    
    2.564
    
    
    
    1.507
    
    
    
    2.772
 December 312005
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001(dollar amounts in thousands)Trust Corpus
    
    $
    10,876
    
    
    
    12,881
    
    
    
    14,730
    
    
    
    16,498
    
    
    
    18,564Total Assets
    
    $
    11,054
    
    
    
    13,052
    
    
    
    15,046
    
    
    
    17,093
    
    
    
    19,086Units outstanding
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
 
 ITEM 7. TRUSTEES DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 Liquidity and Capital Resources
   27




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Results of Operations
     2005 compared to 2004
  2004 compared to 2003
  28




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




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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 BP PRUDHOE BAY ROYALTY TRUST
 Index To Financial Statements
 PageReport of Independent Registered Public Accounting Firm
    
    
    31Statements of Assets, Liabilities and Trust Corpus as of December 31, 2005 and 2004
    
    
    32Statements of Cash Earnings and Distributions for the years ended December 31, 2005, 2004 and 2003
    
    
    33Statements of Changes in Trust Corpus for the years ended December 31 2005, 2004 and 2003
    
    
    34Notes to Financial Statements
    
    
    35
 30




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 Trustee and Holders of Trust Units of BP Prudhoe Bay Royalty Trust:
     Internal ControlIntegrated Framework
    31




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BP Prudhoe Bay Royalty Trust
 
 Statement of Assets, Liabilities and Trust Corpus
 (Prepared on a modified basis of cash receipts and disbursements)
 (In thousands, except unit data)
 December 31,
    
    
    December 31,2005
    
    
    2004AssetsRoyalty Interest, net (Notes 1, 2 and 3)
    
    $
    10,043
    
    
    $
    12,051Cash and cash equivalents (Note 2)
    
    
    1,011
    
    
    
    1,001Total Assets
    
    $
    11,054
    
    
    $
    13,052Liabilities and Trust CorpusAccrued expenses
    
    $
    178
    
    
    $
    171Trust Corpus (40,000,000 units of
beneficial interest authorized,
21,400,000 units issued and outstanding
    
    
    10,876
    
    
    
    12,881Total Liabilities and Trust Corpus
    
    $
    11,054
    
    
    $
    13,052
  32




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BP Prudhoe Bay Royalty Trust
 
 Statements of Cash Earnings and Distributions
 (Prepared on a modified basis of cash receipts and disbursements)
 (In thousands, except unit data)
 December 31,2005
    
    
    2004
    
    
    2003Royalty revenues
    
    $
    152,978
    
    
    $
    82,682
    
    
    $
    55,986Interest income
    
    
    37
    
    
    
    11
    
    
    
    10Less: Trust administrative expenses
    
    
    (1,097
    )
    
    
    (976
    )
    
    
    (1,168
    )Cash earnings
    
    $
    151,918
    
    
    $
    81,717
    
    
    $
    54,828Cash distributions
    
    $
    151,908
    
    
    $
    81,702
    
    
    $
    54,867Cash distributions per unit
    
    $
    7.098
    
    
    $
    3.818
    
    
    $
    2.564Units outstanding
    
    
    21,400,000
    
    
    
    21,400,000
    
    
    
    21,400,000
  33




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##### Table of Contents



BP Prudhoe Bay Royalty Trust
 
 Statements of Changes in Trust Corpus
 (Prepared on a modified basis of cash receipts and disbursements)
 (In thousands)
 December 31,2005
    
    
    2004
    
    
    2003Trust Corpus at beginning of year
    
    $
    12,881
    
    
    $
    14,730
    
    
    $
    16,498Cash earnings
    
    
    151,918
    
    
    
    81,717
    
    
    
    54,828Decrease (increase) in accrued expenses
    
    
    (7
    )
    
    
    145
    
    
    
    279Cash distributions
    
    
    (151,908
    )
    
    
    (81,702
    )
    
    
    (54,867
    )Amortization of Royalty Interest
    
    
    (2,008
    )
    
    
    (2,009
    )
    
    
    (2,008
    )Trust Corpus at end of year
    
    $
    10,876
    
    
    $
    12,881
    
    
    $
    14,730
  
 34




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##### Table of Contents



BP Prudhoe Bay Royalty Trust
 
 Notes to Financial Statements
 (Prepared on a modified basis of cash receipts and disbursements)
 December 31, 2005
 (1)
    
    Formation of the Trust and OrganizationBP Prudhoe Bay Royalty Trust (the Trust), a grantor trust, was created as a Delaware business
trust pursuant to a Trust Agreement dated February 28, 1989 among the Standard Oil Company
(Standard Oil), BP Exploration (Alaska) Inc. (BP Alaska), The Bank of New York (The
Trustee) and The Bank of New York (Delaware), as co-trustee. Standard Oil and BP Alaska are
indirect wholly owned subsidiaries of the BP p.l.c. (BP).On February 28, 1989, Standard Oil conveyed an overriding royalty interest (the Royalty
Interest) to the Trust. The Trust was formed for the sole purpose of owning and administering
the Royalty Interest. The Royalty Interest represents the right to receive, effective February
28, 1989, a per barrel royalty (the Per Barrel Royalty) of 16.4246% on the lesser of (a) the
first 90,000 barrels of the average actual daily net production of oil and condensate per
quarter or (b) the average actual daily net production of oil and condensate per quarter from BP
Alaskas working interest  as of February 28, 1989 in the Prudhoe Bay Field (the
Field),
located on the North Slope of Alaska. Trust Unit holders will remain subject at all times to the
risk that production will be interrupted or discontinued or fall, on average, below 90,000
barrels per day in any quarter. BP has guaranteed the performance of BP Alaska of its payment
obligations with respect to the Royalty Interest.Effective January 1, 2000, BP Alaska and all other Prudhoe Bay working interest owners
cross-assigned interests in the Prudhoe Bay Field pursuant to the Prudhoe Bay Unit Alignment
Agreement. BP Alaska retained all rights, obligations, and liabilities associated with the
Trust.The trustees of the Trust are The Bank of New York, a New York corporation authorized to do a
banking business, and The Bank of New York (Delaware), a Delaware banking corporation. The Bank
of New York (Delaware) serves as co-trustee in order to satisfy certain requirements of the
Delaware Trust Act. The Bank of New York alone is able to exercise the rights and powers granted
to the Trustee in the Trust Agreement.The Per Barrel Royalty in effect for any day is equal to the price of West Texas Intermediate
crude oil (the WTI Price) for that day less scheduled Chargeable Costs (adjusted in certain
situations for inflation) and Production Taxes (based on statutory rates then in existence).The Trust is passive, with the Trustee having only such powers as are necessary for the
collection and distribution of revenues, the payment of Trust liabilities, and the protection of
the Royalty Interest. The Trustee, subject to certain conditions, is obligated to establish cash
reserves and borrow funds to pay liabilities of the Trust when they become due. The Trustee may
sell Trust properties only (a) as authorized by a vote of the Trust Unit Holders, (b) when
necessary to provide for the payment of specific liabilities of the Trust then due (subject to
certain conditions) or (c) upon termination of the Trust. Each Trust Unit issued and outstanding
represents an equal undivided share of beneficial interest in the Trust. Royalty payments are
received by the Trust and distributed to Trust Unit holders, net of Trust expenses, in the month
succeeding the end of each calendar quarter. The Trust will terminate upon the first to occur of
the following events:
 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.
 35




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##### Table of Contents



BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
 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 AccountingThe financial statements of the Trust are prepared on a modified cash basis and reflect the
Trusts assets, liabilities, Corpus, earnings, and distributions, as follows:
 a.
    
    Revenues are recorded when received (generally within 15 days of the end of the
preceding quarter) and distributions to Trust Unit Holders are recorded when paid.b.
    
    Trust expenses (which include accounting, engineering, legal, and other professional
fees, trustees fees, and out-of-pocket expenses) are recorded on an accrual basis.c.
    
    Cash reserves may be established by the Trustee for certain contingencies that would
not be recorded under generally accepted accounting principles.d.
    
    Amortization of the Royalty Interest is calculated based on the units of production
method. Such amortization is charged directly to the Trust Corpus, and does not affect cash
earnings. The daily rate for amortization per net equivalent barrel of oil for the years
ended December 31, 2005, 2004, and 2003 was $0.37. The Trust evaluates impairment of the
Royalty Interest by comparing the undiscounted cash flows expected to be realized from the
Royalty Interest to the carrying value, pursuant to Statement of Financial Accounting
Standards No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets(SFAS
144). If the expected future undiscounted cash flows are less than the carrying value, the
Trust recognizes an impairment loss for the difference between the carrying value and the
estimated fair value of the Royalty Interest.
 While these statements differ from financial statements prepared in accordance with accounting
principles generally accepted in the United States of America, the modified cash basis of
reporting revenues and distributions is considered to be the most meaningful because quarterly
distributions to the Trust Unit Holders are based on net cash receipts. The accompanying
modified cash basis financial statements contain all adjustments necessary to present fairly the
assets, liabilities and Corpus of the Trust as of December 31, 2005 and 2004, and the modified
cash earning and distributions and changes in Trust Corpus for the years ended December 31,
2005, 2004 and 2003. The adjustments are of a normal recurring nature and are, in the opinion of
the Trustee, necessary to fairly present the results of operations.As of December 31, 2005 and 2004, cash equivalents which represent the cash reserve consist of
U.S. treasury bills with an initial term of less than three months.
 Estimates and assumptions are required to be made regarding assets, liabilities and changes in
Trust Corpus resulting from operations when financial statements are prepared. Changes in the
economic
 36




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BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
 environment, financial markets and any other parameters used in determining these
estimates could cause actual results to differ, and the difference could be material.
 (3)
    
    Royalty InterestThe Royalty Interest is comprised of the following at December 31, 2005 and 2004 (in thousands):
 December 31,2005
    
    
    2004Royalty Interest (at inception)
    
    $
    535,000
    
    
    $
    535,000Less:     Accumulated amortization
    
    
    (351,439
    )
    
    
    (349,431
    )Impairment write-down
    
    
    (173,518
    )
    
    
    (173,518
    )Balance, end of period
    
    $
    10,043
    
    
    $
    12,051
 (4)
    
    Income TaxesThe Trust files its federal tax return as a grantor trust subject to the provisions of subpart E
of Part I of Subchapter J of the Internal Revenue Code of 1986, as amended, rather than as an
association taxable as a corporation. The Trust Unit Holders are treated as the owners of Trust
income and Corpus, and the entire taxable income of the Trust will be reported by the Trust Unit
Holders on their respective tax returns.If the Trust were determined to be an association taxable as a corporation, it would be treated
as an entity taxable as a corporation on the taxable income from the Royalty Interest, the Trust
Unit Holders would be treated as shareholders, and distributions to Trust Unit Holders would not
be deductible in computing the Trusts tax liability as an association.
 (5)
    
    Subsequent EventIn February 2006 the Governor of Alaska announced that the State and BP Alaska, ConocoPhilips
and ExxonMobil had reached agreement in principle on a natural gas pipeline contract. The
proposed natural gas pipeline would run from Alaskas North Slope through Canada and into the
Midwestern United States and would be completed in six to eight years. The Governor also
announced that he had proposed legislation to reform the states oil production tax. The
proposed oil and gas production tax would replace the current production tax on oil, which is
based on a percentage of the gross value of production. Under the Governors proposed bill,
producers will pay a tax on net profits and will receive a tradable capital investment tax
credit and a standard deduction. The gas pipeline contract is not final or public and the
Governors tax bill has not been enacted by the Alaska legislature. It is not certain that the
pipeline will be constructed or that the petroleum production tax will be enacted in the form
proposed by the Governor.If the proposed gas pipeline is constructed, extraction of natural gas from the Field will lower reservoir pressure and may accelerate the decline in production from the
reserve volumes attributable to the Trust and the time at which royalty payments to the Trust
will cease. The Trust is not entitled to any royalty payments with respect to natural gas
production from the Field.
 37




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##### Table of Contents



BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
 The Per Barrel Royalty payable to the Trust could be reduced if a new Alaska petroleum
production tax results in an effective rate of tax chargeable against the Royalty Interest that
is higher than the current tax imposed on wellhead value of production.
 (6)
    
    Summary of Quarterly Results (Unaudited)A summary of selected quarterly financial information for the years ended December 31, 2005,
2004, and 2003 is as follows (in thousands, except unit data):
 2005 Fiscal QuarterFirst
    
    
    Second
    
    
    Third
    
    
    FourthRoyalty revenues
    
    $
    33,197
    
    
    
    33,413
    
    
    
    37,357
    
    
    
    49,011Interest income
    
    
    5
    
    
    
    9
    
    
    
    11
    
    
    
    12Trust administrative expenses
    
    
    (151
    )
    
    
    (367
    )
    
    
    (388
    )
    
    
    (191
    )Cash earnings
    
    
    33,051
    
    
    
    33,055
    
    
    
    36,980
    
    
    
    48,832Cash distributions
    
    
    33,051
    
    
    
    33,060
    
    
    
    36,971
    
    
    
    48,826Cash distributions per unit
    
    
    1.5444
    
    
    
    1.5449
    
    
    
    1.7276
    
    
    
    2.2816
 2004 Fiscal QuarterFirst
    
    
    Second
    
    
    Third
    
    
    FourthRoyalty revenues
    
    $
    14,659
    
    
    
    18,342
    
    
    
    21,566
    
    
    
    28,115Interest income
    
    
    2
    
    
    
    3
    
    
    
    2
    
    
    
    4Trust administrative expenses
    
    
    (216
    )
    
    
    (324
    )
    
    
    (212
    )
    
    
    (224
    )Cash earnings
    
    
    14,445
    
    
    
    18,021
    
    
    
    21,356
    
    
    
    27,895Cash distributions
    
    
    14,343
    
    
    
    18,109
    
    
    
    21,352
    
    
    
    27,898Cash distributions per unit
    
    
    0.6702
    
    
    
    0.8462
    
    
    
    0.9978
    
    
    
    1.3036
 2003 Fiscal QuarterFirst
    
    
    Second
    
    
    Third
    
    
    FourthRoyalty revenues
    
    $
    12,538
    
    
    
    17,722
    
    
    
    12,147
    
    
    
    13,579Interest income
    
    
    4
    
    
    
    2
    
    
    
    2
    
    
    
    2Trust administrative expenses
    
    
    (469
    )
    
    
    (333
    )
    
    
    (225
    )
    
    
    (141
    )Cash earnings
    
    
    12,073
    
    
    
    17,391
    
    
    
    11,924
    
    
    
    13,440Cash distributions
    
    
    12,412
    
    
    
    17,291
    
    
    
    11,823
    
    
    
    13,341Cash distributions per unit
    
    
    0.580
    
    
    
    0.808
    
    
    
    0.553
    
    
    
    0.623
 Fiscal Year Ended2005
    
    
    2004
    
    
    2003Royalty revenues
    
    $
    152,978
    
    
    
    82,682
    
    
    
    55,986Interest income
    
    
    37
    
    
    
    11
    
    
    
    10Trust administrative expenses
    
    
    (1,097
    )
    
    
    (976
    )
    
    
    (1,168
    )Cash earnings
    
    
    151,918
    
    
    
    81,702
    
    
    
    54,828Cash distributions
    
    
    151,908
    
    
    
    81,702
    
    
    
    54,867Cash distributions per unit
    
    
    7.098
    
    
    
    3.818
    
    
    
    2.564
 38




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##### Table of Contents



BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
 (7)
    
    Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flow
Relating to Proved Reserves (Unaudited)Pursuant to Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas
Producing Activities(FASB 69), the Trust is required to include in its financial statements
supplementary information regarding estimates of quantities of proved reserves attributable to
the Trust and future net cash flows.Estimates of proved reserves are inherently imprecise and subjective and are revised over time
as additional data becomes available. Such revisions may often be substantial. Information
regarding estimates of proved reserves attributable to the combined interests of BP Alaska and
the Trust were based on reserve estimates prepared by BP Alaska. BP Alaskas reserve estimates are
believed to be reasonable and consistent with presently known physical data concerning the size
and character of the Field.There is no precise method of allocating estimates of physical quantities of reserve volumes
between BP Alaska and the Trust, since the Royalty Interest is not a working interest and the
Trust does not own and is not entitled to receive any specific volume of reserves from the
Field. Reserve volumes attributable to the Trust were estimated by allocating to the Trust its
share of estimated future production from the Field, based on the WTI Price on December 31, 2005
($61.04 per barrel), December 31, 2004 ($43.46 per barrel) and December 31, 2003 ($32.55 per
barrel). Because the reserve volumes attributable to the Trust are estimated using an allocation
of reserve volumes based on the estimated future production and on the current WTI Price, a
change in the timing of estimated production or a change in the WTI price will result in a
change in the Trusts estimated reserve volumes. Therefore, the estimated reserve volumes
attributable to the Trust will vary if different production estimates and prices are used.In addition to production estimates and prices, reserve volumes attributable to the Trust are
affected by the amount of Chargeable Costs that will be deducted in determining the Per Barrel
Royalty. Net proved reserves of oil and condensate attributable to the Trust as of December 31,
2005, 2004 and 2003, based on BP Alaskas latest reserve estimate at such time and the WTI Prices
on December 31, 2005, 2004 and 2003, were estimated to be 85, 77 and 78 million barrels,
respectively (of which 73, 68 and 67 million barrels, respectively, are proved developed). Under
the provisions of FASB 69, no consideration can be given to reserves not considered proved at
the present time.The standardized measure of discounted future net cash flow relating to proved reserves
disclosure required by FASB 69 assigns monetary amounts to proved reserves based on current
prices. This discounted future net cash flow should not be construed as the current market value
of the Royalty Interest. A market valuation determination would include, among other things,
anticipated price changes and the value of additional reserves not considered proved at the
present time or reserves that may be produced after the currently anticipated end of field life.
At December 31, 2005, 2004 and 2003, the standardized measure of discounted future net cash flow
relating to proved reserves attributable to the Trust (estimated in accordance with the
provisions of FASB 69), based on the WTI Prices on those dates of $61.04, $43.46 and $32.55,
respectively, were as follows (in thousands):
 39




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##### Table of Contents



BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
 December 31,2005
    
    
    2004
    
    
    2003Future net cash flows
    
    $
    2,095,163
    
    
    $
    1,130,851
    
    
    $
    644,69110% annual discount for
estimated timing of cash flows
    
    
    (885,424
    )
    
    
    (454,532
    )
    
    
    (249,373
    )Standardized measure of discounted future
net cash flow relating to proved reserves (a)
    
    $
    1,209,739
    
    
    $
    676,319
    
    
    $
    395,318
 
 (a)
    
    The following are the principal sources of the change in the standardized measure of
discounted future net cash flows (in thousands): December 31,2005
    
    
    2004
    
    
    2003Revisions of prior estimates:Reserve volumes
    
    $
    2,472
    
    
    $
    6,123
    
    
    $
    (3,915
    )WTI price
    
    
    787,204
    
    
    
    494,363
    
    
    
    56,270Adjusted chargeable costs
    
    
    (33,736
    )
    
    
    (80,201
    )
    
    
    (15,712
    )Production taxes
    
    
    (116,558
    )
    
    
    (72,641
    )
    
    
    (7,666
    )Other
    
    
    (370
    )
    
    
    (15
    )
    
    
    8639,012
    
    
    
    347,629
    
    
    
    28,985Royalty income received (b)
    
    
    (173,224
    )
    
    
    (106,160
    )
    
    
    (60,943
    )Accretion of discount
    
    
    67,632
    
    
    
    39,532
    
    
    
    38,843Net increase during the year
    
    $
    533,420
    
    
    $
    281,001
    
    
    $
    6,885
 
 (b)
    
    For the purpose of this calculation, royalty income received for 2005, 2004 and 2003
includes the following: Period October 1, 2005 through December 31, 2005
    
    $
    45,246Period October 1, 2004 through December 31, 2004
    
    $
    33,197Period October 1, 2003 through December 31, 2003
    
    $
    14,659
  40




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##### Table of Contents



BP Prudhoe Bay Royalty Trust
Notes to Financial Statements
(Prepared on a modified basis of cash receipts and disbursements)
December 31, 2005
  Estimated net proved reserves of oil and condensate at December 31, 2003
    
    
    77,942Production
    
    
    (5,410
    )Reserve estimate revisions
    
    
    635Change caused by prices/costs
    
    
    4,237Estimated net proved reserves of oil and condensate at December 31, 2004
    
    
    77,404Production
    
    
    (5,395
    )Reserve estimate revisions
    
    
    (1,711
    )Change caused by prices/costs
    
    
    15,015Estimated net proved reserves of oil and condensate at December 31, 2005
    
    
    85,313Proved reserves:December 31, 2003
    
    
    77,942December 31, 2004
    
    
    77,404December 31, 2005
    
    
    85,313
 41




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##### Table of Contents



ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
  
 ITEM 9A. CONTROLS AND PROCEDURES
 Disclosure Controls and Procedures
      42




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##### Table of Contents



Internal Control Over Financial Reporting
 Managements Annual Report on Internal Control Over Financial Reporting. Internal ControlIntegrated Framework
  REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 Trustee and Holders of Trust Units of BP Prudhoe Bay Royalty Trust:
 Internal ControlIntegrated Framework
   43




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##### Table of Contents



Internal ControlIntegrated Framework Internal
ControlIntegrated Framework
     
 Changes in Internal Control Over Financial Reporting.
 
 ITEM 9B. OTHER INFORMATION
  
 PART III
 
 ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
  44




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##### Table of Contents



ITEM 11. EXECUTIVE COMPENSATION
   Transfer Agent andRegistrarYear ended December 31,
    

Trustees Fees
    
    Fees2005
    
    $
    141,288
    
    
    $
    7,0752004
    
    
    116,378
    
    
    
    6,6472003
    
    
    114,572
    
    
    
    7,381
  
 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 Securities Authorized for Issuance under Equity Compensation Plans
  Unit Ownership of Certain Beneficial Owners
  Unit Ownership of Management
  Changes in Control
  
 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
  45




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##### Table of Contents



ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
  2005
    
    
    2004Audit
    
    
    113,000
    
    
    $
    108,000Audit related
    
    
    16,000
    
    
    
    14,500Tax
    
    
    200,000
    
    
    
    200,000Other
    
    
    
    
    
    
    $
    329,000
    
    
    $
    322,500
  
 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
   Report of Independent Registered Public Accounting FirmStatements of Assets, Liabilities and Trust Corpus as of December 31, 2005 and 2004Statements of Cash Earnings and Distributions for the years ended December 31, 2005, 2004 and 2003Statements of Changes in Trust Corpus for the years ended December 31, 2005, 2004 and 2003Notes to Financial Statements
    4.1
    
    BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil
Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson,
Co-Trustee.
 4.2
    
    Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc.
and The Standard Oil Company.4.3
    
    Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay
Royalty Trust.4.4
    
    Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c.,
BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.31
    
    Rule 13a-14(a) certification.32
    
    Section 1350 certification.
 46




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##### Table of Contents



SIGNATURES
 Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 BP PRUDHOE BAY ROYALTY TRUSTBy:
    
    THE BANK OF NEW YORK, as TrusteeBy:
    
    /s/ Ming J. Ryan

     Ming J. RyanVice President
   47




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##### Table of Contents



INDEX TO EXHIBITS
 Exhibit No.
    
    Description4.1*
    
    BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil
Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson,
Co-Trustee.4.2*
    
    Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc.
and The Standard Oil Company.4.3*
    
    Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay
Royalty Trust.4.4*
    
    Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c.,
BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.31
    
    Rule 13a-14(a) certification. Filed herewith32
    
    Section 1350 certification. Filed herewith.
 
 *
    
    Incorporated by reference to the correspondingly numbered exhibit to the Registrants
Annual Report on Form 10-K for the fiscal year ended December 31, 1996 (File No. 1-10243).