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Table of Contents

 
 
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2006
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
         
    Exact Name of Each Registrant as specified in    
Commission   its charter; State of Incorporation; Address;   IRS Employer
File Number   and Telephone Number   Identification No.
1-8962
  PINNACLE WEST CAPITAL CORPORATION
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(602) 250-1000
  86-0512431
1-4473
  ARIZONA PUBLIC SERVICE COMPANY
(an Arizona corporation)
400 North Fifth Street, P.O. Box 53999
Phoenix, Arizona 85072-3999
(602) 250-1000
  86-0011170
     Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
         
PINNACLE WEST CAPITAL CORPORATION
  Yes þ   No o
ARIZONA PUBLIC SERVICE COMPANY
  Yes o   No þ
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.
         
PINNACLE WEST CAPITAL CORPORATION
       
Large accelerated filer þ      Accelerated filer o      Non-accelerated filer o
 
ARIZONA PUBLIC SERVICE COMPANY
       
Large accelerated filer o      Accelerated filer o      Non-accelerated filer þ
     Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act Rule 12b-2).
         
PINNACLE WEST CAPITAL CORPORATION
  Yes o   No þ
ARIZONA PUBLIC SERVICE COMPANY
  Yes o   No þ
     Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
     
PINNACLE WEST CAPITAL CORPORATION
  Number of shares of common stock, no par value, outstanding as of May 3, 2006: 99,197,295
 
   
ARIZONA PUBLIC SERVICE COMPANY
  Number of shares of common stock, $2.50 par value, outstanding as of May 3, 2006: 71,264,947
     Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.
     This combined Form 10-Q is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.
 
 

 


 

TABLE OF CONTENTS
             
        Page
Glossary     2  
        4  
  Financial Statements     4  
 
  Pinnacle West Capital Corporation     4  
 
  Arizona Public Service Company     31  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     40  
  Quantitative and Qualitative Disclosures About Market Risk     61  
  Controls and Procedures     61  
 
           
        62  
  Legal Proceedings     62  
  Risk Factors     62  
  Other Information     62  
  Exhibits     63  
Signatures     65  
 Exhibit 12.1
 Exhibit 12.2
 Exhibit 12.3
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 31.3
 Exhibit 31.4
 Exhibit 32.1
 Exhibit 32.2
 Exhibit 99.1
 Exhibit 99.2

 


Table of Contents

GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
ALJ – Administrative Law Judge
APB – Accounting Principles Board
APS – Arizona Public Service Company, a subsidiary of the Company
APS Energy Services – APS Energy Services Company, Inc., a subsidiary of the Company
Clean Air Act – Clean Air Act, as amended
Company – Pinnacle West Capital Corporation
Credit Agreement – Pinnacle West’s $300 million Amended and Restated Credit Agreement, dated as of December 9, 2005
DOE – United States Department of Energy
EITF – FASB’s Emerging Issues Task Force
El Dorado – El Dorado Investment Company, a subsidiary of the Company
EPA – United States Environmental Protection Agency
ERMC – Energy Risk Management Committee
FASB – Financial Accounting Standards Board
FERC – United States Federal Energy Regulatory Commission
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
kWh – kilowatt-hour
Moody’s – Moody’s Investors Service
MWh – megawatt-hours, one million watts per hour
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
NPC – Nevada Power Company
NRC – United States Nuclear Regulatory Commission
OCI – other comprehensive income
Off-System Sales – sales of electricity from generation owned by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts
Palo Verde – Palo Verde Nuclear Generating Station
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company
PRP – potentially responsible party
PSA – power supply adjustor

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PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
Retail Fuel and Power Costs – fuel and purchased power costs eligible to be deferred under the PSA
Salt River Project – Salt River Project Agricultural Improvement and Power District
SEC – United States Securities and Exchange Commission
SFAS – Statement of Financial Accounting Standards
Silverhawk – Silverhawk Power Station, a 570-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles north of Las Vegas, Nevada
Standard & Poor’s – Standard & Poor’s Corporation
SunCor – SunCor Development Company, a subsidiary of the Company
Sundance Plant – 450-megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona
Superfund – Comprehensive Environmental Response, Compensation and Liability Act
Trading – energy-related activities entered into with the objective of generating profits on changes in market prices
2005 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2005
VIE – variable interest entity

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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)
(dollars and shares in thousands, except per share amounts)
                 
    Three Months Ended  
    March 31,  
    2006     2005  
OPERATING REVENUES
               
Regulated electricity segment
  $ 466,126     $ 416,030  
Marketing and trading segment
    85,002       89,257  
Real estate segment
    107,854       69,936  
Other revenues
    11,224       10,135  
 
           
Total
    670,206       585,358  
 
           
OPERATING EXPENSES
               
Regulated electricity segment fuel and purchased power
    157,395       78,423  
Marketing and trading segment fuel and purchased power
    74,175       70,809  
Operations and maintenance
    178,427       155,084  
Real estate segment operations
    71,330       55,334  
Depreciation and amortization
    87,621       90,944  
Taxes other than income taxes
    35,573       34,565  
Other expenses
    8,522       8,374  
 
           
Total
    613,043       493,533  
 
           
OPERATING INCOME
    57,163       91,825  
 
           
OTHER
               
Allowance for equity funds used during construction
    3,801       2,603  
Other income (Note 14)
    5,467       1,726  
Other expense (Note 14)
    (4,541 )     (5,309 )
 
           
Total
    4,727       (980 )
 
           
INTEREST EXPENSE
               
Interest charges
    47,526       45,965  
Capitalized interest
    (4,024 )     (3,289 )
 
           
Total
    43,502       42,676  
 
           
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    18,388       48,169  
INCOME TAXES
    6,793       18,570  
 
           
INCOME FROM CONTINUING OPERATIONS
    11,595       29,599  
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
               
Net of income tax expense (benefit) of $557 and $(3,320) (Note 17)
    860       (5,151 )
 
           
NET INCOME
  $ 12,455     $ 24,448  
 
           
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC
    99,115       91,962  
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED
    99,449       92,045  
 
               
EARNINGS PER WEIGHTED – AVERAGE COMMON SHARE OUTSTANDING
               
Income from continuing operations – basic
  $ 0.12     $ 0.32  
Net income – basic
    0.13       0.27  
Income from continuing operations – diluted
    0.12       0.32  
Net income – diluted
    0.13       0.27  
DIVIDENDS DECLARED PER SHARE
  $ 1.00     $ 0.95  
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
(dollars in thousands)
                 
    March 31,     December 31,  
    2006     2005  
ASSETS
               
 
               
CURRENT ASSETS
               
Cash and cash equivalents
  $ 314,855     $ 154,003  
Customer and other receivables
    379,730       502,681  
Allowance for doubtful accounts
    (4,596 )     (4,979 )
Materials and supplies (at average cost)
    112,350       109,736  
Fossil fuel (at average cost)
    22,145       23,658  
Assets from risk management and trading activities (Note 10)
    501,871       827,779  
Assets held for sale (Note 17)
          202,645  
Other current assets
    83,406       75,869  
 
           
Total current assets
    1,409,761       1,891,392  
 
           
 
               
INVESTMENTS AND OTHER ASSETS
               
Real estate investments – net
    427,297       390,702  
Assets from long-term risk management and trading activities (Note 10)
    385,100       597,831  
Decommissioning trust accounts
    305,096       293,943  
Other assets
    119,264       111,931  
 
           
Total investments and other assets
    1,236,757       1,394,407  
 
           
 
               
PROPERTY, PLANT AND EQUIPMENT
               
Plant in service and held for future use
    10,838,110       10,727,695  
Less accumulated depreciation and amortization
    3,672,003       3,622,884  
 
           
Total
    7,166,107       7,104,811  
Construction work in progress
    307,950       327,172  
Intangible assets, net of accumulated amortization
    109,435       90,916  
Nuclear fuel, net of accumulated amortization
    61,806       54,184  
 
           
Net property, plant and equipment
    7,645,298       7,577,083  
 
           
 
               
DEFERRED DEBITS
               
Deferred fuel and purchased power regulatory asset (Note 5)
    169,486       172,756  
Other regulatory assets
    167,155       151,123  
Other deferred debits
    127,671       135,884  
 
           
Total deferred debits
    464,312       459,763  
 
           
 
               
TOTAL ASSETS
  $ 10,756,128     $ 11,322,645  
 
           
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
(dollars in thousands)
                 
    March 31,     December 31,  
    2006     2005  
LIABILITIES AND COMMON STOCK EQUITY
               
 
               
CURRENT LIABILITIES
               
Accounts payable
  $ 259,149     $ 377,107  
Accrued taxes
    326,948       289,235  
Accrued interest
    48,828       31,774  
Dividends payable
    49,588        
Short-term borrowings
    10,603       15,673  
Current maturities of long-term debt
    384,055       384,947  
Customer deposits
    64,242       60,509  
Deferred income taxes
    32,160       94,710  
Liabilities from risk management and trading activities (Note 10)
    490,460       720,693  
Other current liabilities (Note 10)
    130,888       297,425  
 
           
Total current liabilities
    1,796,921       2,272,073  
 
           
 
               
LONG-TERM DEBT LESS CURRENT MATURITIES
    2,782,227       2,608,455  
 
           
 
               
DEFERRED CREDITS AND OTHER
               
Deferred income taxes
    1,202,226       1,225,253  
Regulatory liabilities
    571,939       592,494  
Liability for asset retirements
    273,238       269,011  
Pension liability
    285,735       264,476  
Liabilities from long-term risk management and trading activities (Note 10)
    230,629       256,413  
Unamortized gain – sale of utility plant
    44,613       45,757  
Other
    357,869       363,749  
 
           
Total deferred credits and other
    2,966,249       3,017,153  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13 and 15)
               
 
               
COMMON STOCK EQUITY
               
Common stock, no par value
    2,075,157       2,067,377  
Treasury stock
    (895 )     (1,245 )
 
           
Total common stock
    2,074,262       2,066,132  
 
           
Accumulated other comprehensive income (loss) (Note 11):
               
Minimum pension liability adjustment
    (97,277 )     (97,277 )
Derivative instruments
    126,775       262,397  
 
           
Total accumulated other comprehensive income
    29,498       165,120  
 
           
Retained earnings
    1,106,971       1,193,712  
 
           
Total common stock equity
    3,210,731       3,424,964  
 
           
 
               
TOTAL LIABILITIES AND COMMON STOCK EQUITY
  $ 10,756,128     $ 11,322,645  
 
           
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)
(dollars in thousands)
                 
    Three Months Ended  
    March 31,  
    2006     2005 (a)  
CASH FLOWS FROM OPERATING ACTIVITIES
               
Net Income
  $ 12,455     $ 24,448  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization including nuclear fuel
    95,072       99,556  
Deferred fuel and purchased power
    (14,538 )      
Deferred fuel amortization
    17,808        
Allowance for equity funds used during construction
    (3,801 )     (2,603 )
Deferred income taxes
    1,757       (4,281 )
Change in mark-to-market valuations
    9,305       (18,557 )
Changes in current assets and liabilities:
               
Customer and other receivables
    129,940       117,132  
Materials, supplies and fossil fuel
    4,186       (9,967 )
Other current assets
    (7,537 )     (10,265 )
Accounts payable
    (124,577 )     (179,467 )
Accrued taxes
    37,713       31,768  
Other current liabilities
    24,940       22,113  
Proceeds from the sale of real estate assets
    7,884       19,427  
Real estate investments
    (28,670 )     (13,797 )
Change in risk management and trading – assets
    67,984       (1,198 )
Change in risk management and trading – liabilities
    (66,096 )     37,707  
Collateral
    (170,690 )     32,946  
Change in other long-term assets
    (2,247 )     (1,676 )
Change in other long-term liabilities
    12,169       19,064  
 
           
Net cash flow provided by operating activities
    3,057       162,350  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES
               
Capital expenditures
    (167,367 )     (121,120 )
Proceeds from the sale of Silverhawk
    207,620        
Capitalized interest
    (4,024 )     (3,289 )
Purchases of investment securities
    (269,526 )     (343,525 )
Proceeds from sale of investment securities
    269,526       424,700  
Proceeds from nuclear decommissioning trust sales
    33,743       39,777  
Investment in nuclear decommissioning trust
    (38,929 )     (42,638 )
Proceeds from real estate investments
    2,138       1,869  
Other
    (1,484 )     8,999  
 
           
Net cash flow provided by (used for) investing activities
    31,697       (35,227 )
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES
               
Issuance of long-term debt
    206,848       163,999  
Short-term borrowings and payments – net
    (70 )     (7,778 )
Dividends paid on common stock
    (49,608 )     (43,666 )
Repayment of long-term debt
    (39,587 )     (264,805 )
Common stock equity issuance
    5,065       12,649  
Other
    3,450       21,228  
 
           
Net cash flow provided by (used for) financing activities
    126,098       (118,373 )
 
           
 
               
NET INCREASE IN CASH AND CASH EQUIVALENTS
    160,852       8,750  
 
               
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    154,003       163,366  
 
           
 
               
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 314,855     $ 172,116  
 
           
 
               
Supplemental disclosure of cash flow information
               
Cash paid during the period for:
               
Income taxes paid, net of refunds
  $ (40 )   $ 15,230  
Interest paid, net of amounts capitalized
  $ 25,526     $ 33,891  
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.
 
(a)   See Note 1 for information regarding revisions of prior year amounts.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Consolidation and Nature of Operations
     The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our wholly-owned subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado. All significant intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.
     In the second quarter of 2005, Pinnacle West revised the presentation of its statements of cash flows to include the cash flows from discontinued operations within the categories of operating, investing, and financing activities. A summary of the effects of the change in presentation on the Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2005 is as follows (dollars in millions):
         
    Three Months Ended  
    March 31, 2005  
Net cash flows from operating activities as previously reported
  $ 196  
Change in net cash flows from discontinued operations
    (34 )
 
     
Net cash flows from operating activities as currently reported
  $ 162  
 
     
Net cash flows used for investing activities as previously reported
  $ (40 )
Change in net cash flows used for discontinued operations
    5  
 
     
Net cash flows used for investing activities as currently reported
  $ (35 )
 
     
Net cash flows used for financing activities as previously reported
  $ (147 )
Change in net cash flows used for discontinued operations
    29  
 
     
Net cash flows used for financing activities as currently reported
  $ (118 )
 
     
2. Condensed Consolidated Financial Statements
     Our unaudited condensed consolidated financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. We suggest that these condensed consolidated financial statements and notes to condensed consolidated financial statements be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2005 Form 10-K.
3. Quarterly Fluctuations
     Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate and trading and wholesale marketing activities can have significant impacts on our results for

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
interim periods. For these reasons, results for interim periods do not necessarily represent results to be expected for the year.
4. Changes in Liquidity
      In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk. See “Equity Infusions” in Note 5 for more information.
     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).
     On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.
     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions) as of March 31, 2006:
                 
Year   Pinnacle West   APS
2006
  $ 386     $ 85  
2007
    2       1  
2008
    112       1  
2009
    10       1  
2010
    228       224  
Thereafter
    2,439       2,262  
5. Regulatory Matters
APS General Rate Case
     On January 31, 2006, APS filed with the ACC updated financial schedules, testimony and other data in the general rate case that APS originally filed on November 4, 2005. As requested by the ACC staff, the updated information uses the twelve months ended September 30, 2005 as the test period instead of the test year ended December 31, 2004 used in APS’ original filing. As a result of the updated filing, APS is requesting a 21.3%, or $453.9 million, increase in its annual retail electricity revenues effective no later than December 31, 2006. The original filing requested a 19.9%, or $409.1 million, retail rate increase.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
     The updated requested rate increase is designed to recover the following (dollars in millions):
                                 
    Updated Filing     Original Filing  
    (January 31, 2006)     (November 4, 2005)  
    Annual             Annual        
    Revenue     Percentage     Revenue     Percentage  
    Increase     Increase     Increase     Increase  
Increased fuel and purchased power
  $ 299.0       14.0 %   $ 246.8       12.0 %
Capital structure update
    98.3       4.6 %     96.8       4.7 %
Rate base update, including acquisition of Sundance Plant
    46.2       2.2 %     42.5       2.1 %
Pension funding
    41.3       1.9 %     41.2       2.0 %
Other items
    (30.9 )     (1.4 )%     (18.2 )     (0.9 )%
 
                       
 
                               
Total increase
  $ 453.9       21.3 %   $ 409.1       19.9 %
 
                       
     The request is based on (a) a rate base of $4.4 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.031904 per kilowatt-hour based on estimated 2006 prices; and (c) a proposed capital structure of 45% long-term debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common stock equity). The requested increase in annual retail electricity revenues from the original filing is based solely on increased fuel and purchased power costs, slightly offset by other items (see the above chart). If the ACC approves the requested base rate increase for fuel and purchased power costs (see clause (b) of this paragraph), subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs would be recovered in base rates.
     The updated request does not include the PSA annual adjustor rate increase of approximately 5% that took effect February 1, 2006 or the pending application for a PSA surcharge that APS filed on February 2, 2006. See “Power Supply Adjustor” below.
Interim Rate Increase
     On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate increase of $299 million, or approximately 14%, to be effective April 1, 2006. APS later reduced this request to $232 million, or approximately 11%, due to a decline in expected 2006 natural gas and wholesale power prices. The purpose of the emergency interim rate increase is solely to address APS’ under-collection of higher annual fuel and purchased power costs. On May 2, 2006, the ACC approved an order in this matter that, among other things:
    authorizes an interim PSA adjustor, effective May 1, 2006, that will result in an interim retail rate increase of approximately 8.3% designed to recover approximately $138 million of fuel and purchased power costs during 2006 (this interim adjustor, combined with the $15 million PSA surcharge approved by the ACC (see “Application for PSA Surcharges” below), will result in a rate increase of

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      approximately 9.0% designed to recover approximately $149 million of fuel and purchased power costs during 2006);
 
    provides that amounts collected through the interim PSA adjustor “remain subject to a prudency review at the appropriate time” and that “all unplanned Palo Verde outage costs for 2006 should undergo a prudence audit by [the ACC] Staff” (PSA deferrals related to these outages are estimated to be about $32 million during the quarter ended March 31, 2006);
 
    encourages parties to APS’ general rate case to “propose modifications to the PSA that will address on a permanent basis, the issues with timing of recovery when deferrals are large and growing”;
 
    affirms APS’ ability to defer fuel and purchased power costs above the prior annual cap of $776.2 million until the ACC decides the general rate case; and
 
    encourages APS to diversify its resources “through large scale, sustained energy efficiency programs, [using] low cost renewable energy resources as a hedge against high fossil fuel costs.”
The interim PSA adjustor accelerates recovery of the fuel and purchased power component of APS’ general rate case and is not an additional increase.
Power Supply Adjustor
     PSA Provisions
     The PSA approved by the ACC in April 2005 as part of APS’ 2003 rate case provides for adjustment of retail rates to reflect variations in retail fuel and purchased power costs. On January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, is subject to specified parameters and procedures, including the following:
    APS will record deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the base fuel amount (currently $0.020743 per kWh);
 
    the deferrals are subject to a 90/10 sharing arrangement in which APS must absorb 10% of the retail fuel and purchased power costs above the base fuel amount and may retain 10% of the benefit from the retail fuel and purchased power costs that are below the base fuel amount;
 
    amounts to be recovered or refunded through the PSA adjustor are limited to a)  a cumulative plus or minus $0.004 per kWh from the base fuel amount over the life of the PSA and b) a maximum plus or minus $0.004 change in the adjustor rate in any one year;

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    the recoverable amount of annual retail fuel and purchased power costs through current base rates and the PSA was originally capped at $776.2 million; however, the ACC has removed the cap pending the ACC’s final ruling on APS’ pending request in the general rate case to have the cap eliminated or substantially raised;
 
    the PSA will remain in effect for a minimum five-year period, but the ACC may eliminate the PSA at any time, if appropriate, in the event APS files a rate case before the expiration of the five-year period (which APS did by filing the general rate case noted above) or if APS does not comply with the terms of the PSA; and
 
    APS is prohibited from requesting PSA surcharges until after the PSA annual adjustor rate has been set each year. The amount available for potential PSA surcharges will be limited to the amount of accumulated deferrals through the prior year-end, which are not expected to be recovered through the annual adjustor or any PSA surcharges previously approved by the ACC.
     2006 PSA Annual Adjustor The effective date of the PSA’s annual adjustor is February 1, and the adjustor rate was set at the maximum $0.004 per kilowatt-hour effective February 1, 2006. The change in the adjustor rate represents a retail rate increase of approximately 5% designed to recover $110 million of deferred fuel and purchased power costs over the twelve-month period beginning February 1, 2006, of which $18 million was recorded as revenue and fuel and purchased power costs during the quarter ended March 31, 2006.
     Application for PSA Surcharges On February 2, 2006, APS filed with the ACC an application for two separate surcharges under the PSA. The surcharges would recover approximately $60 million in retail fuel and purchased power costs deferred by APS in 2005 under the PSA. The combined surcharges would represent a temporary rate increase of approximately 2.6% during the overlapping portion of the twelve-month recovery periods for the two surcharges. The other component of the 2005 PSA deferrals is being recovered under the 2006 PSA annual adjustor discussed in the preceding paragraph. The first surcharge would recover approximately $15 million over a twelve-month period, representing a temporary rate increase of approximately 0.7%, proposed to begin with the date of the ACC’s decision in APS’ emergency interim rate case. The second requested surcharge would recover approximately $45 million over a twelve-month period, representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages. The $45 million of PSA deferrals represents replacement power costs associated with these outages. On April 12, 2006, the ACC issued an order approving the $15 million surcharge request. As a result of the ACC’s decision described under “Interim Rate Increase” above, this temporary rate increase became effective May 1, 2006. The second surcharge request is still pending.
     Proposed Modifications to PSA (Requested In General Rate Case)
     In its pending general rate case, APS has requested the following modifications to the PSA:
    The cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 limit to changes in the adjustor rate in any one year would remain in effect;

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    The $776.2 million annual limit on the retail fuel and purchased power costs under APS’ current base rates and the PSA would be removed or increased (although APS may defer fuel and purchased power costs above $776.2 million per year pending the ACC’s final ruling on APS’ pending request to have the cap eliminated or substantially raised);
 
    The current provision that APS is required to file a surcharge application with the ACC after accumulated pretax PSA deferrals equal $50 million and before they equal $100 million would be eliminated, thereby giving APS flexibility in determining when a surcharge filing should be made;
 
    The costs of renewable energy and capacity costs attributable to purchased power obtained through competitive procurement would be excluded from the existing 90/10 sharing arrangement under which APS absorbs 10% of the retail fuel and purchased power costs above the base fuel amount and retains 10% of the benefit from retail fuel and purchased power costs that are below the base fuel amount; and
 
    10% of any realized gains or losses resulting from APS’ hedges of Retail Fuel and Power Costs would be retained or absorbed by APS before being subject to the 90/10 sharing provision under the PSA.
APS 2003 Rate Case
     On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003. In addition to the ACC’s approval of the PSA discussed under “Power Supply Adjustor” above, certain key financial components of the order include:
    APS received an annual retail rate increase of approximately 4.2%, which was effective as of April 1, 2005. This increase does not include the impact of the PSA.
 
    APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was $139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $84 million in the third quarter of 2005.
 
    Effective April 1, 2005, APS adopted longer service lives for certain depreciable assets. This change reduced annual depreciation expense for financial reporting purposes by approximately $30 million. APS also adopted longer service lives for the PWEC Dedicated Assets, which reduced annual depreciation expense for financial reporting purposes by approximately $10 million.

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Equity Infusions
     On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consist of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006 (see Note 17). Pinnacle West has made these equity infusions into APS.
Federal
     Price Mitigation Plan
     In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.
     FERC Order
     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to its three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.
     On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ market-based rate authority in the APS control area (the “FERC Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the APS control area to allow the FERC to make a determination about the FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.
     As a result of the FERC Order, the Pinnacle West Companies must charge cost-based rates, rather than market-based rates, in the APS control area, with an effective date of February 27, 2005. The Pinnacle West Companies will be required to refund any over-collection of rates from February 27, 2005.
     The Pinnacle West Companies will seek rehearing of the FERC Order on or before May 17, 2006. Based upon an analysis of the FERC Order and preliminary calculations of the refund obligations, at this time, neither Pinnacle West nor APS believes that the FERC Order has a material adverse effect on its financial position, results of operations or cash flows.
     In addition, the FERC Order revoked a previously-granted FERC order allowing Pinnacle West to issue securities or incur long-term debt without FERC approval. On May 3, 2006, the FERC issued an order approving Pinnacle West’s April 20, 2006 application to borrow funds under the Credit Agreement and to issue a broad range of other debt and equity securities.

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6. Retirement Plans and Other Benefits
     Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a nonqualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.
     The following table provides details of the plans’ benefit costs for the three months ended March 31, 2006 and 2005. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or capitalized as overhead construction (dollars in millions):
                                 
    Pension Benefits     Other Benefits  
    Three Months     Three Months  
    Ended     Ended  
    March 31,     March 31,  
    2006     2005     2006     2005  
Service cost-benefits earned during the period
  $ 15     $ 12     $ 7     $ 6  
Interest cost on benefit obligation
    29       23       13       9  
Expected return on plan assets
    (30 )     (24 )     (13 )     (8 )
Amortization of:
                               
Transition (asset) obligation
          (1 )     1       1  
Prior service cost
    1       1              
Net actuarial loss
    7       5       3       2  
 
                       
Net periodic benefit cost
  $ 22     $ 16     $ 11     $ 10  
 
                       
Portion of cost charged to expense
  $ 9     $ 7     $ 5     $ 4  
 
                       
APS’ share of costs charged to expense
  $ 8     $ 6     $ 4     $ 4  
 
                       
Contributions
     The contribution to our pension plan in 2006 is estimated to be approximately $50 million, $14 million of which was contributed on April 14, 2006. The contribution to our other postretirement benefit plans in 2006 is estimated to be approximately $29 million. APS’ share is approximately 97% of both plans.

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7. Business Segments
     We have three principal business segments (determined by products, services and the regulatory environment):
    our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution;
 
    our real estate segment, which consists of SunCor’s real estate development and investment activities; and
 
    our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.
     Financial data for the three months ended March 31, 2006 and 2005 and at March 31, 2006 and December 31, 2005 by business segment is provided as follows (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Operating Revenues:
               
Regulated electricity
  $ 466     $ 416  
Real estate
    108       70  
Marketing and trading
    85       89  
Other
    11       10  
 
           
Total
  $ 670     $ 585  
 
           
 
               
Net Income (Loss):
               
Regulated electricity
  $ (12 )   $ 14  
Real estate
    21       9  
Marketing and trading
    2        
Other
    1       1  
 
           
Total
  $ 12     $ 24  
 
           

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    As of     As of  
    March 31, 2006     December 31, 2005  
Assets:
                 
Regulated electricity
  $ 9,756       $ 9,732  
Real estate
    517         483  
Marketing and trading
    452         1,070  
Other
    31         38  
 
         
Total
  $ 10,756       $ 11,323  
 
         
8. Stock-Based Compensation
     Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and our subsidiaries.
     The 2002 Long-Term Incentive Plan (“2002 Plan”) allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. We have reserved 6 million shares of common stock for issuance under the 2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The term of the option cannot be longer than 10 years and the option cannot be repriced during its term.
     Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year period based upon PinnacleWest’s earnings per share growth rate during that three-year period compared to the earnings per share growth rate of all relevant companies in a specified utilities index. The number of shares of common stock a recipient is entitled to receive is determined by Pinnacle West’s relative percentile ranking during the three-year period.
     The 1994 Long-Term Incentive Plan (“1994 Plan”) includes outstanding options but no new options may be granted under the plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.
     In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25, “Accounting for Stock Issued to Employees.”
     Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective application transition method. Because the fair value recognition provisions of both SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based

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compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements.
     The compensation cost that has been charged against income for share-based compensation plans was $2.9 million and $0.6 million for the quarters ended March 31, 2006 and 2005, respectively. The total income tax benefit recognized in the condensed consolidated income statement for share-based compensation arrangements was $1.1 million and $0.2 million for the quarters ended March 31, 2006 and 2005, respectively.
     The following table is a summary of option activity under our equity incentive plans as of March 31, 2006 and changes during the quarter ending on that date:
                                 
                    Weighted-        
                    Average     Aggregate  
            Weighted-     Remaining     Intrinsic Value  
      Shares     Average Exercise     Contractual Term     (dollars in  
Options                                                               (in thousands)     Price     (Years)     thousands)  
Outstanding at January 1, 2006
    1,696     $ 39.65                  
Granted
                           
Exercised
    (2 )     32.29                  
Forfeited or expired
    (6 )     43.29                  
 
                             
Outstanding at March 31, 2006
    1,688       39.64       4.9     $ 2,930  
 
                             
Exercisable at March 31, 2006
    1,682       39.65       4.9       2,923  
 
                             
     There were no options granted during the quarters ended March 31, 2006 and 2005. The intrinsic value of options exercised during the quarters ended March 31, 2006 and 2005 was not material.
     The following table is a summary of the status of stock compensation awards, other than options, as of March 31, 2006 and changes during the quarter ending on that date:
                 
    Shares   Weighted-Average Grant-Date
Nonvested shares   (in thousands)   Fair Value
Nonvested at January 1, 2006
    528     $ 38.23  
Granted
    274       41.50  
Vested
    (13 )     44.13  
Forfeited
    (217 )     35.96  
 
               
Nonvested at March 31, 2006
    572       40.52  
 
               
     As of March 31, 2006, there was $10.4 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested during the quarters ended March 31, 2006 and 2005 was $0.5 million and $2.9 million, respectively.

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     Cash received from options exercised under our share-based payment arrangements for the quarter ended March 31, 2006 was $0.1 million and for the quarter ended March 31, 2005 was $4.0 million. The actual tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was immaterial for the three months ended March 31, 2006 or 2005.
     Pinnacle West has a current policy of issuing new shares to satisfy share requirements for stock compensation plans and does not expect to repurchase any shares during 2006.
9. Variable-Interest Entities
     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.
     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2006, APS would have been required to assume approximately $234 million of debt and pay the equity participants approximately $185 million.
10. Derivative and Energy Trading Accounting
     We use derivative instruments (primarily forward purchases and sales, swaps, options and futures) to manage our exposure to the commodity price risk inherent in the purchase and sale of fuel, electricity and emission allowances and credits, as well as interest rate risk associated with long-term debt. As of March 31, 2006, we hedged exposures to the price variability of the power and gas commodities for a maximum of 3.25 years. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
Cash Flow Hedges
     The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2006 and 2005 are comprised of the following (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                 
    Three Months Ended
    March 31,
    2006   2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting
  $ (178 )   $ 7,324  
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness
    (18 )     858  
Gains from the discontinuance of cash flow hedges
    434       385  
     During the next twelve months ending March 31, 2007, we estimate that a net gain of $73 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).
     Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments.
     The following table summarizes our assets and liabilities from risk management and trading activities at March 31, 2006 and December 31, 2005 (dollars in thousands):
March 31, 2006
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
    Assets     Assets     Liabilities     Other     (Liability)  
Regulated electricity:
                                       
Mark-to-market
  $ 381,639     $ 194,319     $ (350,517 )   $ (121,356 )   $ 104,085  
Margin account and options
    45             (58,224 )           (58,179 )
Marketing and trading:
                                       
Mark-to-market
    118,925       178,740       (58,668 )     (108,466 )     130,531  
Options and emission allowances – at cost
    1,262       12,041       (23,051 )     (807 )     (10,555 )
 
                             
Total
  $ 501,871     $ 385,100     $ (490,460 )   $ (230,629 )   $ 165,882  
 
                             

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December 31, 2005
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
    Assets     Assets     Liabilities     Other     (Liability)  
Regulated electricity:
                                       
Mark-to-market
  $ 516,399     $ 228,873     $ (335,801 )   $ (74,787 )   $ 334,684  
Margin account and options
    1,814             (124,165 )           (122,351 )
Marketing and trading:
                                       
Mark-to-market
    307,883       291,122       (236,922 )     (181,417 )     180,666  
Options and emission allowances – at cost
    1,683       77,836       (23,805 )     (209 )     55,505  
 
                             
Total
  $ 827,779     $ 597,831     $ (720,693 )   $ (256,413 )   $ 448,504  
 
                             
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was a liability of $57 million at March 31, 2006 and $123 million at December 31, 2005 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.
     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $10 million at March 31, 2006 and $6 million at December 31, 2005, and is included in other current assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $46 million at March 31, 2006 and $216 million at December 31, 2005, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.
Fair Value Hedges
     On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% Senior Notes. The purpose of these hedges was to protect against significant fluctuations in the fair value of our debt. These interest rate swaps were considered to be fully effective with any resulting gains or losses on the derivative offset by a similar loss or gain amount on the underlying fair value of our debt. The fair value of the interest rate swaps was a loss of approximately $1.7 million at March 31, 2006 and is included in other current liabilities with the corresponding offset in current maturities of long-term debt on the Condensed Consolidated Balance Sheets. These interest rate swaps were settled in April 2006.
Credit Risk
     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 10% of Pinnacle West’s $887

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
million of risk management and trading assets as of March 31, 2006. Our risk management process assesses and monitors the financial exposure of this and all other counterparties. Despite the fact that the great majority of trading counterparties’ securities are rated as investment grade by the credit rating agencies, including the counterparty discussed above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
11. Comprehensive Income (Loss)
     Components of comprehensive income (loss) for the three months ended March 31, 2006 and 2005 are as follows (dollars in thousands):
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Net income
  $ 12,455     $ 24,448  
 
           
Other comprehensive income (loss):
               
Net unrealized gains (losses) on derivative instruments (a)
    (204,983 )     159,644  
Net reclassification of realized gains to income (b)
    (17,530 )     (5,919 )
Net income tax benefit (expense) related to items of other comprehensive income (loss)
    86,891       (60,306 )
 
           
Total other comprehensive income (loss)
    (135,622 )     93,419  
 
           
Comprehensive income (loss)
  $ (123,167 )   $ 117,867  
 
           
 
(a)   These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.
 
(b)   These amounts primarily include the reclassification of unrealized gains and losses to realized for contracted commodities delivered during the period.

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12. Commitments and Contingencies
Palo Verde Nuclear Generating Station
     Spent Nuclear Fuel and Waste Disposal
     Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims.
     APS currently estimates it will incur $147 million (in 2005 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2006, APS had a regulatory asset of $4 million that represents amounts spent for on-site interim spent fuel storage net of amounts recovered in rates per the ACC rate order that was effective April 1, 2005.
California Energy Market Issues and Refunds in the Pacific Northwest
     FERC
     In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006, the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.
     On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under

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market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing has not been acted upon, and the outcome of the further proceedings cannot be predicted at this time.
     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals. Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or cash flows.
     On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.
FERC Order
     See “FERC Order” in Note 5 for a discussion of an order issued by the FERC on April 17, 2006.
Natural Gas Supply
     Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium through December 31, 2005.
     On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party has sought appellate review and is seeking to reallocate the costs responsibility associated with the changed contractual obligations in a way that would be less favorable to APS and Pinnacle West Energy than under the FERC’s July 9, 2003 order.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Should this party prevail on this point, APS and Pinnacle West Energy’s annual capacity cost could be increased by approximately $3 million after income taxes for the period September 2003 through December 2005. This appeal has been stayed pending further consideration by the FERC.
     Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on June 30, 2005, which proposed new rates and new services to become effective on January 1, 2006. The FERC allowed the new rates to take effect on January 1, 2006, but made the rates subject to refund pending the outcome of a hearing. On March 23, 2006, the FERC issued an order approving El Paso’s proposed new services. APS has sought rehearing of this order. On March 29, 2006, El Paso filed a partial settlement that postpones the implementation and the associated cost impact of the new services until June 1, 2006. As part of this settlement, El Paso will accept bids for new services that will be evaluated and awarded on a net present value, first-come, first-serve basis. APS will be able to evaluate the cost impact of these new services once it has been notified of the services contracts it has been awarded. APS cannot currently predict the outcome of this matter; however, APS believes most of these increased costs would be eligible for recovery under the PSA (see Note 5).
Navajo Nation Litigation
     In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.
     In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.
Superfund
     Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures which may be required.
Litigation
     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations, cash flows or liquidity.
13. Nuclear Insurance
     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $15 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $13 million.
     The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $17.8 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
14. Other Income and Other Expense
     The following table provides detail of other income and other expense for the three months ended March 31, 2006 and 2005 (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Other income:
               
Interest income
  $ 4,905     $ 1,320  
Asset sales
    361       241  
SunCor (a)
    166       (28 )
Miscellaneous
    35       193  
 
           
Total other income
  $ 5,467     $ 1,726  
 
           
 
               
Other expense:
               
Non-operating costs (b)
  $ (3,719 )   $ (3,098 )
Asset sales
    (196 )     (64 )
Investment losses – net
    (31 )     (1,249 )
Miscellaneous
    (595 )     (898 )
 
           
Total other expense
  $ (4,541 )   $ (5,309 )
 
           
 
(a)   Includes joint venture and other non-operating income.
 
(b)   As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and other costs excluded from utility rate recovery).
15. Guarantees
     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of one of our unregulated subsidiaries. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our unregulated subsidiary would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of its subsidiary. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. At March 31, 2006, we had a guarantee of $18 million with a term of one year and a surety bond of $65 million with a term of one year for APS Energy Services.
     At March 31, 2006, Pinnacle West had approximately $4 million of letters of credit related to workers’ compensation expiring in 2006. These letters of credit were subsequently extended and expire in 2007. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
     APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2006, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $93 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
in 2006. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
     We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
16. Earnings Per Share
     The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2006 and 2005:
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Basic earnings per share:
               
Income from continuing operations
  $ 0.12     $ 0.32  
Income (loss) from discontinued operations
    0.01       (0.05 )
 
           
Earnings per share – basic
  $ 0.13     $ 0.27  
 
           
 
               
Diluted earnings per share:
               
Income from continuing operations
  $ 0.12     $ 0.32  
Income (loss) from discontinued operations
    0.01       (0.05 )
 
           
Earnings per share – diluted
  $ 0.13     $ 0.27  
 
           
     Dilutive stock options and performance shares increased average common shares outstanding by approximately 334,000 shares and 83,000 shares for the three months ended March 31, 2006 and March 31, 2005, respectively.
     Options to purchase 747,874 shares for the three-month period ended March 31, 2006 were outstanding but were not included in the computation of earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share for that same reason were 868,934 shares for the three-month period ended March 31, 2005.
17. Discontinued Operations
     Silverhawk (marketing and trading segment) In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
January 10, 2006. The marketing and trading segment discontinued operations amounts in the chart below are the revenues and expenses related to the operations of Silverhawk.
     SunCor (real estate segment) In 2005 and 2006, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144.
     The following table provides revenue and income (loss) before income taxes and after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2006 and 2005 (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Revenue:
               
Silverhawk
  $ 1     $ 28  
SunCor – commercial operations
    1       4  
 
           
Total revenue
  $ 2     $ 32  
 
           
 
               
Income (loss) before taxes:
               
Silverhawk (a)
  $     $ (10 )
SunCor – commercial operations
    1       2  
 
           
Total income (loss) before taxes
  $ 1     $ (8 )
 
           
 
               
Income (loss) after taxes:
               
Silverhawk
  $     $ (7 )
SunCor – commercial operations
          1  
 
           
Total income (loss) after taxes
  $     $ (6 )
 
           
 
(a)   For the three months ended March 31, 2005, income (loss) before income taxes includes an interest expense allocation, net of capitalized costs, of $3 million. The allocation was based on Pinnacle West’s weighted-average interest rate applied to the net property, plant and equipment.
18. Nuclear Decommissioning Trust
     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in debt and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, APS has recorded the offsetting amount of unrealized gains (losses) on investment securities in other regulatory liabilities/assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at March 31, 2006 and December 31, 2005 (dollars in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                         
            Total     Total  
            Unrealized     Unrealized  
    Fair Value     Gains     Losses  
March 31, 2006
                       
Equity securities
  $ 160     $ 56     $  
Debt securities
    145       1       2  
 
                 
Total
  $ 305     $ 57     $ 2  
 
                 
 
                       
December 31, 2005
                       
Equity securities
  $ 150     $ 50     $  
Debt securities
    144       3       1  
 
                 
Total
  $ 294     $ 53     $ 1  
 
                 
     The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
                 
    Three Months Ended March 31,
    2006   2005
Realized gains
  $ 1     $ 1  
Realized losses
    (1 )     (1 )
Proceeds from the sale of securities
    34       40  
     The fair value of debt securities, summarized by contractual maturities, at March 31, 2006 is as follows:
         
    March 31,  
Fair Value (in millions)   2006  
Less than one year
  $ 10  
1 year - 5 years
    36  
5 years - 10 years
    38  
Greater than 10 years
    61  
 
     
Total
  $ 145  
 
     

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME

(unaudited)
(dollars in thousands)
                 
    Three Months Ended  
    March 31,  
    2006     2005  
ELECTRIC OPERATING REVENUES
               
Regulated electricity
  $ 467,222     $ 418,434  
Marketing and trading
    9,647       22,858  
 
           
Total
    476,869       441,292  
 
           
 
               
OPERATING EXPENSES
               
Regulated electricity fuel and purchased power
    158,274       81,914  
Marketing and trading fuel and purchased power
    1,368       28,302  
Operations and maintenance
    173,353       142,294  
Depreciation and amortization
    86,311       82,214  
Income taxes
    (3,029 )     16,380  
Other taxes
    35,548       31,445  
 
           
Total
    451,825       382,549  
 
           
OPERATING INCOME
    25,044       58,743  
 
           
 
               
OTHER INCOME (DEDUCTIONS)
               
Income taxes
    236       (837 )
Allowance for equity funds used during construction
    3,801       2,603  
Other income (Note S-3)
    4,806       6,161  
Other expense (Note S-3)
    (3,680 )     (3,860 )
 
           
Total
    5,163       4,067  
 
           
 
               
INTEREST DEDUCTIONS
               
Interest on long-term debt
    34,250       35,517  
Interest on short-term borrowings
    2,026       1,191  
Debt discount, premium and expense
    1,173       1,004  
Allowance for borrowed funds used during construction
    (1,721 )     (1,947 )
 
           
Total
    35,728       35,765  
 
           
 
               
NET INCOME (LOSS)
  $ (5,521 )   $ 27,045  
 
           
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS

(unaudited)
(dollars in thousands)
                 
    March 31,     December 31,  
    2006     2005  
ASSETS
               
 
               
UTILITY PLANT
               
Electric plant in service and held for future use
  $ 10,793,563     $ 10,682,999  
Less accumulated depreciation and amortization
    3,665,740       3,616,886  
 
           
Total
    7,127,823       7,066,113  
 
               
Construction work in progress
    292,893       314,584  
Intangible assets, net of accumulated amortization
    108,922       90,327  
Nuclear fuel, net of accumulated amortization
    61,806       54,184  
 
           
Utility plant – net
    7,591,444       7,525,208  
 
           
 
               
INVESTMENTS AND OTHER ASSETS
               
Decommissioning trust accounts
    305,096       293,943  
Assets from long-term risk management and trading activities (Note S-1)
    198,329       234,372  
Other assets
    65,612       64,128  
 
           
Total investments and other assets
    569,037       592,443  
 
           
 
               
CURRENT ASSETS
               
Cash and cash equivalents
    76,645       49,933  
Customer and other receivables
    304,569       421,621  
Allowance for doubtful accounts
    (3,192 )     (3,568 )
Materials and supplies (at average cost)
    112,350       109,736  
Fossil fuel (at average cost)
    22,145       23,658  
Assets from risk management and trading activities (Note S-1)
    387,426       532,923  
Other current assets
    10,229       14,639  
 
           
Total current assets
    910,172       1,148,942  
 
           
 
               
DEFERRED DEBITS
               
Deferred fuel and purchased power regulatory asset (Note 5)
    169,486       172,756  
Other regulatory assets
    167,155       151,123  
Unamortized debt issue costs
    24,630       25,279  
Other deferred debits
    87,291       91,690  
 
           
Total deferred debits
    448,562       440,848  
 
           
 
               
TOTAL ASSETS
  $ 9,519,215     $ 9,707,441  
 
           
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS

(unaudited)
(dollars in thousands)
                 
    March 31,     December 31,  
    2006     2005  
CAPITALIZATION AND LIABILITIES
               
 
               
CAPITALIZATION
               
Common stock
  $ 178,162     $ 178,162  
Additional paid-in capital (Note 5)
    2,063,098       1,853,098  
Retained earnings
    770,154       860,675  
Accumulated other comprehensive income (loss):
               
Minimum pension liability adjustment
    (86,132 )     (86,132 )
Derivative instruments
    73,974       179,422  
 
           
Common stock equity
    2,999,256       2,985,225  
Long-term debt less current maturities
    2,479,689       2,479,703  
 
           
Total capitalization
    5,478,945       5,464,928  
 
           
 
               
CURRENT LIABILITIES
               
Current maturities of long-term debt
    85,018       85,620  
Accounts payable
    149,529       215,384  
Accrued taxes
    391,080       360,737  
Accrued interest
    35,262       25,003  
Dividends payable
    42,500        
Customer deposits
    57,192       55,474  
Deferred income taxes
    8,682       64,210  
Liabilities from risk management and trading activities (Note S-1)
    413,299       480,138  
Other current liabilities (Note S-1)
    97,012       227,398  
 
           
Total current liabilities
    1,279,574       1,513,964  
 
           
 
               
DEFERRED CREDITS AND OTHER
               
Deferred income taxes
    1,205,489       1,215,403  
Regulatory liabilities
    571,939       592,494  
Liability for asset retirements
    273,238       269,011  
Pension liability
    253,298       233,342  
Customer advances for construction
    62,248       60,287  
Unamortized gain – sale of utility plant
    44,613       45,757  
Liabilities from long-term risk management and trading activities (Note S-1)
    129,029       83,774  
Other
    220,842       228,481  
 
           
Total deferred credits and other
    2,760,696       2,728,549  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13, 15 and S-4)
               
 
               
TOTAL CAPITALIZATION AND LIABILITIES
  $ 9,519,215     $ 9,707,441  
 
           
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)
(dollars in thousands)
                 
    Three Months Ended  
    March 31,  
    2006     2005  
CASH FLOWS FROM OPERATING ACTIVITIES
               
Net income (loss)
  $ (5,521 )   $ 27,045  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depreciation and amortization including nuclear fuel
    93,762       87,539  
Deferred fuel and purchased power
    (14,538 )      
Deferred fuel amortization
    17,808        
Allowance for equity funds used during construction
    (3,801 )     (2,603 )
Deferred income taxes
    1,757       (1,009 )
Change in mark-to-market valuations
    974       (8,234 )
Changes in current assets and liabilities:
               
Customer and other receivables
    124,568       70,493  
Materials, supplies and fossil fuel
    (1,101 )     (5,309 )
Other current assets
    4,892       3,089  
Accounts payable
    (62,543 )     (123,460 )
Accrued taxes
    30,343       47,839  
Collateral
    (150,640 )     31,080  
Other current liabilities
    32,231       (29,573 )
Change in risk management and trading activities – liabilities
    (65,131 )     36,204  
Change in other long-term assets
    (5,335 )     (11,821 )
Change in other long-term liabilities
    11,366       6,168  
 
           
Net cash flow provided by operating activities
    9,091       127,448  
 
           
CASH FLOWS FROM INVESTING ACTIVITIES
               
Capital expenditures
    (140,185 )     (117,501 )
Allowance for borrowed funds used during construction
    (1,721 )     (1,947 )
Purchases of investment securities
    (122,025 )     (67,450 )
Proceeds from sale of investment securities
    122,025       248,625  
Proceeds from nuclear decommissioning trust sales
    33,743       39,777  
Investment in nuclear decommissioning trust
    (38,929 )     (42,638 )
Other
    (1,966 )     8,934  
 
           
Net cash flow provided by (used for) investing activities
    (149,058 )     67,800  
 
           
CASH FLOWS FROM FINANCING ACTIVITIES
               
Issuance of long-term debt
          163,975  
Equity infusion
    210,000        
Dividends paid on common stock
    (42,500 )     (42,500 )
Repayment and reacquisition of long-term debt
    (821 )     (264,482 )
 
           
Net cash flow provided by (used for) financing activities
    166,679       (143,007 )
 
           
NET INCREASE IN CASH AND CASH EQUIVALENTS
    26,712       52,241  
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    49,933       49,575  
 
           
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 76,645     $ 101,816  
 
           
Supplemental disclosure of cash flow information:
               
Cash paid during the year for:
               
Income taxes paid, net of refunds
  $     $ 9  
Interest, net of amounts capitalized
  $ 24,297     $ 30,149  
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

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     Certain notes to APS’ Condensed Financial Statements are combined with the Notes to Pinnacle West’s Condensed Consolidated Financial Statements. Listed below are the Condensed Consolidated Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS’ Condensed Financial Statements. In addition, listed below are the Supplemental Notes which are required disclosures for APS and should be read in conjunction with Pinnacle West’s Condensed Consolidated Notes.
         
    Condensed   APS’
    Consolidated   Supplemental
    Footnote   Footnote
    Reference   Reference
Consolidation and Nature of Operations
  Note 1  
Condensed Consolidated Financial Statements
  Note 2  
Quarterly Fluctuations
  Note 3  
Changes in Liquidity
  Note 4  
Regulatory Matters
  Note 5  
Retirement Plans and Other Benefits
  Note 6  
Business Segments
  Note 7  
Stock-Based Compensation
  Note 8  
Variable Interest Entities
  Note 9  
Derivative and Energy Trading Accounting
  Note 10   Note S-1
Comprehensive Income
  Note 11   Note S-2
Commitments and Contingencies
  Note 12  
Nuclear Insurance
  Note 13  
Other Income and Other Expense
  Note 14   Note S-3
Guarantees
  Note 15  
Earnings Per Share
  Note 16  
Discontinued Operations
  Note 17  
Nuclear Decommissioning Trust
  Note 18  
Related Party Transactions
    Note S-4

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
S-1. Derivative and Energy Trading Accounting
     APS is exposed to the impact of market fluctuations in the commodity price of electricity, natural gas, coal and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels, and emission allowances and credits. As of March 31, 2006, APS hedged exposures to these risks for a maximum of 3.25 years.
Cash Flow Hedges
     The changes in the fair value of APS’ hedged positions included in the APS Condensed Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2006 and 2005 were comprised of the following (dollars in thousands):
                 
    Three Months Ended
    March 31,
    2006   2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting
  $ (436 )   $ 7,417  
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness
    (18 )     858  
Gains from the discontinuance of cash flow hedges
    159       302  
     During the next twelve months ending March 31, 2007, APS estimates that a net gain of $41 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).
     APS’ assets and liabilities from risk management and trading activities are presented in two categories, consistent with Pinnacle West’s business segments.
     The following table summarizes APS’ assets and liabilities from risk management and trading activities at March 31, 2006 and December 31, 2005 (dollars in thousands):

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
March 31, 2006
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
    Assets     Assets     Liabilities     Other     (Liability)  
Regulated Electricity:
                                       
Mark-to-market
  $ 381,639     $ 194,319     $ (350,517 )   $ (121,356 )   $ 104,085  
Margin account and options
    45             (58,224 )           (58,179 )
Marketing and Trading:
                                       
Mark-to-market
    4,480       4,010       (4,347 )     (6,866 )     (2,723 )
Options at cost
    1,262             (211 )     (807 )     244  
 
                             
Total
  $ 387,426     $ 198,329     $ (413,299 )   $ (129,029 )   $ 43,427  
 
                             
December 31, 2005
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
    Assets     Assets     Liabilities     Other     (Liability)  
Regulated Electricity:
                                       
Mark-to-market
  $ 516,399     $ 228,873     $ (335,801 )   $ (74,787 )   $ 334,684  
Margin account and options
    1,814             (124,165 )           (122,351 )
Marketing and Trading:
                                       
Mark-to-market
    13,027       5,499       (20,172 )     (8,778 )     (10,424 )
Options at cost
    1,683                   (209 )     1,474  
 
                             
Total
  $ 532,923     $ 234,372     $ (480,138 )   $ (83,774 )   $ 203,383  
 
                             
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was a liability of $57 million at March 31, 2006 and $123 million at December 31, 2005 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.
     Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. No collateral was provided to counterparties at March 31, 2006 or December 31, 2005. Collateral provided to us by counterparties was $24 million at March 31, 2006 and $175 million at December 31, 2005, and is included in other current liabilities on the Condensed Balance Sheets.
S-2. Comprehensive Income (Loss)
     Components of APS’ comprehensive income (loss) for the three months ended March 31, 2006 and 2005 are as follows (dollars in thousands):

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Net income (loss)
  $ (5,521 )   $ 27,045  
 
           
Other comprehensive income (loss):
               
Net unrealized gains (losses) on derivative instruments (a)
    (162,892 )     108,217  
Net reclassification of realized gains to income (b)
    (10,116 )     (1,381 )
Net income tax benefit (expense) related to items of other comprehensive income (loss)
    67,560       (42,061 )
 
           
Total other comprehensive income (loss)
    (105,448 )     64,775  
 
           
Comprehensive income (loss)
  $ (110,969 )   $ 91,820  
 
           
 
(a)   These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.
 
(b)   These amounts primarily include the reclassification of unrealized gains and losses to realized gains and losses for contracted commodities delivered during the period.
S-3. Other Income and Other Expense
     The following table provides detail of APS’ other income and other expense for the three months ended March 31, 2006 and 2005 (dollars in thousands):
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Other income:
               
Interest income
  $ 3,534     $ 5,423  
Asset sales
    361       241  
Investment gains – net
    875        
Miscellaneous
    36       497  
 
           
Total other income
  $ 4,806     $ 6,161  
 
           
 
               
Other expense:
               
Non-operating costs (a)
  $ (3,216 )   $ (2,628 )
Asset sales
    (196 )     (64 )
Investment losses – net
          (502 )
Miscellaneous
    (268 )     (666 )
 
           
Total other expense
  $ (3,680 )   $ (3,860 )
 
           
 
(a)   As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and other costs excluded from utility rate recovery).

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
S-4. Related Party Transactions
     From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other subsidiaries. The following table summarizes the amounts included in the APS Condensed Statements of Income and Condensed Balance Sheets related to transactions with affiliated companies (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Electric operating revenues:
               
Pinnacle West – marketing and trading
  $ 1     $ 1  
Pinnacle West Energy
          1  
 
           
Total
  $ 1     $ 2  
 
           
 
               
Fuel and purchased power costs:
               
Pinnacle West Energy
  $     $ 8  
 
           
 
               
Other:
               
Pinnacle West Energy interest income
  $     $ 5  
 
           
                 
    As of     As of  
    March 31, 2006     December 31, 2005  
Net intercompany receivables (payables):
               
Pinnacle West – marketing and trading
  $ 27     $ 82  
APS Energy Services
    1       2  
Pinnacle West
    (17 )     (2 )
 
           
Total
  $ 11     $ 82  
 
           
     Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. APS purchases electricity from and sells electricity to APS Energy Services; however, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.”
     Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
     The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and Arizona Public Service Company’s Condensed Financial Statements and the related Notes that appear in Item 1 of this report.
OVERVIEW
     Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.
     The ACC regulates APS’ retail electric rates. The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 5, APS has pending before the ACC:
    a general retail rate case pursuant to which APS is requesting a 21.3%, or $453.9 million, increase in its annual retail electricity revenues effective no later than December 31, 2006; and
 
    an application for a temporary rate increase of approximately 1.9%, through a PSA surcharge, to recover $45 million in retail fuel and purchased power costs relating to Palo Verde’s 2005 unplanned outages, which were deferred by APS in 2005 under the PSA.
     See “Deferred Fuel and Purchased Power Costs” below for a discussion of Palo Verde Unit 1’s current outage to remedy an operating condition, the unit’s previous reduced power levels resulting from that condition, and the associated economic impact.
     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow. Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and industrial retail customers in the western United States. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures.
     Pinnacle West Energy is our subsidiary that previously owned and operated unregulated generating plants. Pursuant to the ACC’s April 7, 2005 order in APS’ 2003 rate case, on July 29, 2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. See “APS 2003 Rate Case” in Note 5. Pinnacle West Energy sold its 75% interest in Silverhawk to NPC on January 10, 2006. See Note 17 for discussion of discontinued operations. As a result, Pinnacle West Energy no longer owns any generating plants and has ceased operations.
     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction.

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We plan to expand long-term resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.
     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
     Pinnacle West has three principal business segments (determined by products, services and the regulatory environment):
    our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution;
 
    our real estate segment, which consists of SunCor’s real estate development and investment activities; and
 
    our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.
     The following table summarizes net income for the three months ended March 31, 2006 and 2005 (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2006     2005  
Regulated electricity
  $ (12 )   $ 14  
Real estate
    21       8  
Marketing and trading
    2       7  
Other
    1       1  
 
           
Income from continuing operations
    12       30  
Discontinued operations – net of tax:
               
Real estate (a)
          1  
Marketing and trading (b)
          (7 )
 
           
Net income
  $ 12     $ 24  
 
           
 
(a)   Primarily relates to sales of commercial properties.
 
(b)   Primarily relates to the operations of Silverhawk.

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PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS
General
     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to operating revenues less fuel and purchased power costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.1 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior-period amounts to conform to our current-period presentation.
Deferred Fuel and Purchased Power Costs
     APS’ retail rate settlement became effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.
     The balance of APS’ pretax deferred fuel and purchased power regulatory asset (“PSA deferrals”) at March 31, 2006 was $169 million. Based on the ACC’s approval of the May 1, 2006 interim adjustor and $15 million PSA surcharge (see “Interim Rate Increase” and “Application for PSA Surcharges” in Note 5), APS estimates that its pretax PSA deferral balance at December 31, 2006 will be approximately $160 million to $180 million assuming no additional interim rate relief and based on APS’ hedged positions for fuel and purchased power at March 31, 2006; recent forward market prices for natural gas and purchased power (which are subject to change); strong performance from APS’ fossil-fueled generating units during the three months ended March 31, 2006; and the operating performance at Palo Verde Unit 1 discussed below.
     The PSA deferral balances at March 31, 2006 and estimated at December 31, 2006 each include $45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages. APS has requested the recovery of these deferrals through a PSA surcharge upon the ACC’s completion of an inquiry regarding the outages.
     APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18, 2006 due to vibration levels in one of the Unit’s shutdown cooling lines. APS began a planned outage of Unit 1 on March 18, 2006 and, based on early inspections and testing during that outage, determined to perform the necessary work and modifications to remedy the situation prior to returning the Unit to service. APS believes that performing the work during the current Unit 1 outage will provide greater assurance that Unit 1 will be operating during the peak summer months and somewhat accelerate returning the Unit to full power (which is currently expected in the June timeframe).

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APS estimates that pretax incremental replacement power costs resulting from Unit 1’s current outage and reduced power levels were approximately $36 million during the three months ended March 31, 2006 and that such costs will be approximately $47 million in the second quarter of 2006. The related PSA deferrals were approximately $32 million in the three months ended March 31, 2006 and are estimated to be approximately $42 million in the second quarter of 2006. The Palo Verde replacement power costs were partially offset by $17 million of lower replacement power costs related to strong performance from APS’ fossil-fueled generating units during the three months ended March 31, 2006. As a result, the corresponding deferrals were reduced in the quarter by $15 million. As noted under “Interim Rate Increase” under Note 5, the ACC has directed the ACC staff to undertake a prudence audit of all unplanned 2006 Palo Verde outage costs.
     See Note 5 for further information regarding the PSA and APS’ pending PSA surcharge application.
Operating Results – Three-month period ended March 31, 2006 compared with three-month period ended March 31, 2005
     Our consolidated net income for the three months ended March 31, 2006 was $12 million compared with $24 million for the comparable prior-year period. The three months ended March 31, 2005 included an after-tax net loss from discontinued operations of $6 million, which was related primarily to the operations of Silverhawk, partially offset by sales of commercial properties at SunCor. Income from continuing operations decreased $18 million in the period-to-period comparison, reflecting the following changes in earnings by segment:
    Regulated Electricity Segment – Income from continuing operations decreased approximately $26 million primarily due to higher fuel and purchased power costs (as discussed above) and higher prices, and higher operations and maintenance expense related to generation and customer service costs. These negative factors were partially offset by deferred fuel and purchased power costs; higher retail sales volumes due to customer growth; a retail price increase effective April 1, 2005; and higher interest income.
 
    Real Estate Segment – Income from continuing operations increased approximately $13 million primarily due to increased parcel and home sales.
 
    Marketing and Trading Segment – Income from continuing operations decreased approximately $5 million primarily due to lower mark-to-market gains on contracts for future delivery and the absence of Off-System Sales that we began reporting in the regulated electricity segment in April 2005.

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Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):
                 
    Increase (Decrease)  
    Pretax     After Tax  
Regulated electricity segment gross margin:
               
Higher fuel and purchased power costs
  $ (55 )   $ (34 )
Deferred fuel and purchased power costs (fuel deferrals began April 1, 2005)
    13       8  
Higher retail sales volumes due to customer growth, excluding weather effects
    13       8  
Retail price increase effective April 1, 2005
    7       4  
Effects of weather on retail sales
    (3 )     (2 )
Miscellaneous items, net
    (4 )     (2 )
 
           
Net decrease in regulated electricity segment gross margin
    (29 )     (18 )
 
           
Marketing and trading segment gross margin:
               
Lower mark-to-market gains on contracts for future delivery due to changes in forward prices
    (9 )     (6 )
Lower realized margins on wholesale sales primarily due to the absence of sales that we began reporting in the regulated segment in April 2005
    (5 )     (3 )
Miscellaneous items, net
    6       4  
 
           
Net decrease in marketing and trading segment gross margin
    (8 )     (5 )
 
           
Net decrease in gross margin for regulated electricity and marketing and trading segments
    (37 )     (23 )
Higher real estate segment contribution primarily related to increased parcel and home sales
    22       13  
Operations and maintenance increases primarily due to:
               
Generation costs, including maintenance and overhauls
    (18 )     (11 )
Customer service costs, including regulatory demand-side management programs and planned maintenance
    (5 )     (3 )
Depreciation and amortization decreases primarily due to lower depreciation rates, partially offset by increased depreciable assets
    3       2  
Higher other income, net of expense primarily due to increased interest income
    5       3  
Miscellaneous items, net
          1  
 
           
Net decrease in income from continuing operations
  $ (30 )     (18 )
 
             
Discontinued operations related to:
               
Silverhawk operations in 2005
            7  
Sales of real estate assets
            (1 )
 
             
Net decrease in net income
          $ (12 )
 
             

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     Regulated Electricity Segment Revenues
     Regulated electricity segment revenues were $50 million higher for the three months ended March 31, 2006 compared with the prior-year period primarily as a result of:
    a $19 million increase in retail revenues related to customer growth, excluding weather effects;
 
    an $18 million increase in revenues related to the implementation of the February 1, 2006 PSA adjustor, which has no earnings effect due to the offset from amortization of deferred fuel in fuel and purchased power expense;
 
    a $12 million increase in Off-System Sales primarily resulting from sales previously reported in the marketing and trading segment that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;
 
    a $7 million increase in retail revenues due to a price increase effective April 1, 2005;
 
    a $4 million decrease in retail revenues related to weather; and
 
    a $2 million decrease due to miscellaneous factors.
     Marketing and Trading Segment Revenues
     Marketing and trading segment revenues were $4 million lower for the three months ended March 31, 2006 compared with the prior-year period primarily as a result of:
    a $22 million increase from higher volumes of competitive retail sales in California;
 
    a $12 million decrease in Off-System Sales due to the absence of sales previously reported in the marketing and trading segment that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;
 
    a $9 million decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices; and
 
    a $5 million decrease due to miscellaneous factors.
     Real Estate Revenues
     Real estate revenues were $38 million higher for the three months ended March 31, 2006 compared with the prior-year period primarily due to increased parcel and home sales at SunCor.

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LIQUIDITY AND CAPITAL RESOURCES
Capital Needs and Resources – Pinnacle West Consolidated
     Capital Expenditure Requirements
     The following table summarizes the actual capital expenditures for the three months ended March 31, 2006 and estimated capital expenditures for the next three years:
CAPITAL EXPENDITURES
(dollars in millions)
                                 
    Three Months Ended     Estimated for the Year Ended  
    March 31,     December 31,  
    2006     2006     2007     2008  
APS
                               
Distribution
  $ 86     $ 322     $ 323     $ 362  
Transmission
    25       120       169       203  
Generation
    31       184       207       279  
Other (a)
    6       23       16       13  
 
                       
Subtotal
    148       649       715       857  
SunCor (b)
    46       232       142       119  
Other
    1       6       2       6  
 
                       
Total
  $ 195     $ 887     $ 859     $ 982  
 
                       
 
(a)   Primarily information systems and facilities projects.
 
(b)   Consists primarily of capital expenditures for land development and retail and office building construction reflected in “Real estate investments” on the Condensed Consolidated Statements of Cash Flows.
     Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth.
     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants and the replacement of Palo Verde steam generators (see below). Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Generation also includes nuclear fuel expenditures of approximately $35 million annually for 2006 through 2008.
     Replacement of the steam generators at Palo Verde Unit 1 was completed during the fall 2005 outage at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of one additional set of steam generators. These generators will be installed in Unit

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3 and are scheduled for completion in the fall of 2007 at an approximate cost of $75 million (APS’ share). Approximately $20 million of the Unit 3 steam generator costs have been incurred through 2005 with the remaining $55 million included in future years in the capital expenditures table above. Capital expenditures will be funded with internally generated cash and/or external financings.
Contractual Obligations
     Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2005 Form 10-K with the exception of our aggregate:
    fuel and purchased power commitments, which increased from approximately $1.9 billion at December 31, 2005 to $3 billion at March 31, 2006 as follows (in billions):
                 
2006   2007-2008   2009-2010   Thereafter   Total
$0.4
  $0.5   $0.4   $1.7   $3.0
     See Note 4 for a list of payments due on total long-term debt and capitalized lease requirements.
     Off-Balance Sheet Arrangements
     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.
     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2006, APS would have been required to assume approximately $234 million of debt and pay the equity participants approximately $185 million.
     Guarantees and Letters of Credit
     We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to these obligations. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 15 for additional information regarding guarantees and letters of credit.
     Credit Ratings
     The ratings of securities of Pinnacle West and APS as of May 8, 2006 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue

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for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 10).
         
    Moody’s   Standard & Poor’s
Pinnacle West
       
Senior unsecured1
  (P) Baa3   BB+ (prelim)
Commercial paper
  P-3   A-3
Outlook
  Negative   Stable
APS
       
Senior unsecured
  Baa2   BBB-
Secured lease obligation bonds
  Baa2   BBB-
Commercial paper
  P-2   A-3
Outlook
  Negative   Stable
 
1 Pinnacle West has a shelf registration under SEC rule 415. Moody’s assigns a provisional (P) rating and Standard & Poor’s assigns a preliminary (prelim) rating to such shelf registrations. Pinnacle West currently has no outstanding, rated senior unsecured securities.
     Debt Provisions
     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt to capitalization ratio. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For each of Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At March 31, 2006, the ratio was approximately 50% for Pinnacle West and 46% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage is approximately 3.6 times under APS’ bank financing agreements as of March 31, 2006. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.
     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, in the event of a further rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
     All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under

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these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
     See Note 4 for further discussions.
Capital Needs and Resources — By Company
     Pinnacle West (Parent Company)
     Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
     Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At March 31, 2006, APS’ common equity ratio, as defined, was approximately 54%.
     Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our subsidiaries. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. The assets in the plan are comprised of common stocks, bonds, common and collective trusts and short-term investments. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. We contributed $53 million in 2005. The contribution to our pension plan in 2006 is estimated to be approximately $50 million, $14 million of which was contributed on April 14, 2006. The contribution to our other postretirement benefit plans in 2006 is estimated to be approximately $29 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.
     In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk. See “Equity Infusions” in Note 5 for more information.
     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).
     On March 22, 2006, the Pinnacle West Board of Directors declared a quarterly dividend of $0.50 per share of common stock, payable on June 1, 2006, to shareholders of record on May 1, 2006.

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     On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April, 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.
     APS
     APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.
     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.
     See “Deferred Fuel and Purchased Power Costs” above and “Power Supply Adjustor” in Note 5 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.
     See “Cash Flow Hedges” in Note 10 for information related to collateral provided to us by counterparties.
     Pinnacle West Energy
     See Note 17 of Notes to Condensed Consolidated Financial Statements above for a discussion of the sale of our 75% ownership interest in Silverhawk.
     Other Subsidiaries
     During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures during the three months ended March 31, 2006 and projected capital expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.
     El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
     APS Energy Services expects minimal capital expenditures over the next three years.
CRITICAL ACCOUNTING POLICIES
     In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting

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period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting, the determination of the appropriate accounting for our pension and other postretirement benefits and derivatives accounting. There have been no changes to our critical accounting policies since our 2005 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2005 Form 10-K for further details about our critical accounting policies.
PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING
OUR FINANCIAL OUTLOOK
Factors Affecting Operating Revenues, Fuel and Purchased Power Costs
     General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity rates and tariffs and variations in weather from period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition.
     Retail Rate Proceedings The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 5, APS has pending before the ACC a general retail rate case and an application for a surcharge under the PSA.
     Fuel and Purchased Power Costs Fuel and purchased power costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service, variances in deferrals and amortization of fuel and purchased power beginning on April 1, 2005 and our hedging program for managing such costs. See “Power Supply Adjustor” in Note 5 for information regarding the PSA approved by the ACC. See “Natural Gas Supply” in Note 12 for more information on fuel costs. See “Deferred Fuel and Purchased Power Costs” for information about Palo Verde Unit 1’s current outage to remedy an operating condition, the unit’s previous reduced power levels resulting from that condition, and the associated economic impact. APS’ recovery of PSA deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.
     Customer and Sales Growth The customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory averaged about 3.8% a year for the three years 2003 through 2005; we currently expect customer growth to average about 3.8% per year from 2006 to 2008. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.7% on average, from 2006 through 2008, before the effects of weather variations. Customer growth for the three-month period ended March 31, 2006 compared with the prior-year period was 4.5%.
     Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and responses to retail price changes. Our experience indicates that a reasonable range of variation in our

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kilowatt-hour sales projection attributable to such economic factors can result in increases or decreases in annual net income of up to $10 million.
     Weather In forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.
     Wholesale Power Market Conditions The marketing and trading division focuses primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. The marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits.
Other Factors Affecting Financial Results
     Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.
     Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction, acquisition, the sale of generation (see discussion of the sale of Silverhawk – Note 17), changes in depreciation and amortization rates (see Note 5), and changes in regulatory asset amortization.
     Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed value for 2005 and 2004. We expect property taxes to increase as new power plants, the acquisition of the Sundance Plant in 2005 and our additions to transmission and distribution facilities are included in the property tax base.
     Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.
     Retail Competition Although some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
     Subsidiaries SunCor’s net income was $56 million in 2003, $45 million in 2004 and $56 million in 2005. See Note 17 for further discussion.
     APS Energy Services’ and El Dorado’s historical results are not indicative of future performance.

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     General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.
Market Risks
     Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.
     Interest Rate and Equity Risk
     We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of debt securities held by our nuclear decommissioning trust fund. The nuclear decommissioning trust fund also has risk associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.
     Commodity Price Risk
     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
     The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:
    Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and
 
    Marketing and Trading – non-trading and trading derivative instruments of our competitive business segment.
     The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions for the three months ended March 31, 2006 and 2005 (dollars in millions):

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    Three Months Ended     Three Months Ended  
    March 31, 2006     March 31, 2005  
    Regulated     Marketing     Regulated     Marketing  
    Electricity     and Trading     Electricity     and Trading  
Mark-to-market of net positions at beginning of period
  $ 335     $ 181     $ 33     $ 107  
Recognized in earnings:
                               
Change in mark-to-market for future period deliveries – gains (losses)
    (5 )           13       14  
Mark-to-market gains realized including ineffectiveness during the period
    (4 )     (1 )           (8 )
Deferred as a regulatory asset
    (49 )                  
Recognized in OCI:
                               
Change in mark-to-market for future period deliveries – gains (losses) (a)
    (163 )     (42 )     108       52  
Mark-to-market gains realized during the period
    (10 )     (7 )     (1 )     (5 )
 
                       
Mark-to-market of net positions at end of period
  $ 104     $ 131     $ 153     $ 160  
 
                       
 
(a)   The increases (decreases) in regulated mark-to-market recorded in OCI are due primarily to increases (decreases) in forward natural gas prices.
     The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at March 31, 2006 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2005 Form 10-K for more discussion of our valuation methods.
Regulated Electricity
                                                         
                                                    Total  
                                            Years     fair  
Source of Fair Value   2006     2007     2008     2009     2010     thereafter     value  
Prices actively quoted
  $ 19     $ 83     $ 32     $ 2     $     $     $ 136  
Prices provided by other external sources
          6             (1 )                 5  
Prices based on models and other valuation methods
    (3 )     (3 )     (4 )     (1 )     (3 )     (23 )     (37 )
 
                                         
Total by maturity
  $ 16     $ 86     $ 28     $     $ (3 )   $ (23 )   $ 104  
 
                                         

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Marketing and Trading
                                                 
                                            Total  
                                            fair  
Source of Fair Value   2006     2007     2008     2009     2010     value  
Prices actively quoted
  $ 52     $     $     $     $     $ 52  
Prices provided by other external sources
          70       19                   89  
Prices based on models and other valuation methods
    (21 )     (3 )     16       (1 )     (1 )     (10 )
 
                                   
Total by maturity
  $ 31     $ 67     $ 35     $ (1 )   $ (1 )   $ 131  
 
                                   
     The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at March 31, 2006 and December 31, 2005 (dollars in millions).
                                 
    March 31, 2006     December 31, 2005  
    Gain (Loss)     Gain (Loss)  
    Price Up     Price Down     Price Up     Price Down  
Commodity   10%     10%     10%     10%  
Mark-to-market changes reported in earnings (a):
                               
Electricity
  $ (1 )   $ 1     $     $  
Natural gas
                       
Other
                       
Mark-to-market changes reported in OCI (b):
                               
Electricity
    54       (54 )     66       (66 )
Natural gas
    90       (90 )     103       (103 )
 
                       
 
                               
Total
  $ 143     $ (143 )   $ 169     $ (169 )
 
                       
 
(a)   These contracts are primarily structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.
 
(b)   These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.
Credit Risk
     We are exposed to losses in the event of non-performance or non-payment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 10% of Pinnacle West’s $887 million of risk management and trading assets as of March 31, 2006. See Note 1, “Derivative

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Accounting” in Item 8 of our 2005 Form 10-K for a discussion of our credit valuation adjustment policy. See Note 10 for further discussion of credit risk.
ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS
General
     Throughout the following explanations of our results of operations, we refer to “gross margin.” Gross margin refers to electric operating revenues less fuel and purchased power costs. Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.2 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior-period amounts to conform to our current-period presentation.
Deferred Fuel and Purchased Power Costs
     APS’ retail rate settlement became effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.
     The balance of APS’ pretax deferred fuel and purchased power regulatory asset (“PSA deferrals”) at March 31, 2006 was $169 million. Based on the ACC’s approval of the May 1, 2006 interim adjustor and $15 million PSA surcharge (see “Interim Rate Increase” and “Application for PSA Surcharges” in Note 5), APS estimates that its pretax PSA deferral balance at December 31, 2006 will be approximately $160 million to $180 million assuming no additional interim rate relief and based on APS’ hedged positions for fuel and purchased power at March 31, 2006; recent forward market prices for natural gas and purchased power (which are subject to change); strong performance from APS’ fossil-fueled generating units during the three months ended March 31, 2006; and the operating performance at Palo Verde Unit 1 discussed below.
     The PSA deferral balances at March 31, 2006 and estimated at December 31, 2006 each include $45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages. APS has requested the recovery of these deferrals through a PSA surcharge upon the ACC’s completion of an inquiry regarding the outages.
     APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18, 2006 due to vibration levels in one of the Unit’s shutdown cooling lines. APS began a planned outage of Unit 1 on March 18, 2006 and, based on early inspections and testing during that outage, determined to perform the necessary work and modifications to remedy the situation prior to returning the Unit to service. APS believes that performing the work during the current Unit 1 outage will provide greater assurance that Unit 1 will be operating during the peak summer months

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and somewhat accelerate returning the Unit to full power (which is currently expected in the June timeframe). APS estimates that pretax incremental replacement power costs resulting from Unit 1’s current outage and reduced power levels were approximately $36 million during the three months ended March 31, 2006 and that such costs will be approximately $47 million in the second quarter of 2006. The related PSA deferrals were approximately $32 million in the three months ended March 31, 2006 and are estimated to be approximately $42 million in the second quarter of 2006. The Palo Verde replacement power costs were partially offset by $17 million of lower replacement power costs related to strong performance from APS’ fossil-fueled generating units during the three months ended March 31, 2006. As a result, the corresponding deferrals were reduced in the quarter by $15 million. As noted under “Interim Rate Increase” under Note 5, the ACC has directed the ACC staff to undertake a prudence audit of all unplanned 2006 Palo Verde outage costs.
     See Note 5 for further information regarding the PSA and APS’ pending PSA surcharge application.
Operating Results – Three-month period ended March 31, 2006 compared with three-month period ended March 31, 2005
     APS had a net loss of $6 million for the three-month period ended March 31, 2006 compared with net income of $27 million for the comparable prior-year period. The $33 million decrease was primarily due to higher fuel and purchased power costs (as discussed above) and higher prices, and higher operations and maintenance expense related to generation (including the PWEC Dedicated Assets APS acquired on July 29, 2005) and customer service costs. These negative factors were partially offset by deferred fuel and purchased power costs; higher mark-to-market gains on contracts for future delivery; higher retail sales volumes due to customer growth; and a retail price increase effective April 1, 2005.
     Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

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    Increase (Decrease)  
    Pretax     After Tax  
Gross margin:
               
Higher fuel and purchased power costs
  $ (53 )   $ (32 )
Deferred fuel and purchased power costs (fuel deferrals began April 1, 2005)
    13       8  
Higher mark-to-market gains on contracts for future delivery due to changes in forward prices
    14       9  
Higher retail sales volumes due to customer growth, excluding weather effects
    13       8  
Retail price increase effective April 1, 2005
    7       4  
Effects of weather on retail sales
    (3 )     (2 )
Miscellaneous items, net
    (5 )     (3 )
 
           
Net decrease in gross margin
    (14 )     (8 )
Operations and maintenance increases primarily due to:
               
Generation costs, including maintenance and overhauls
    (16 )     (10 )
Costs of PWEC Dedicated Assets not included in prior year period
    (8 )     (5 )
Customer service costs, including regulatory demand-side management programs and planned maintenance
    (5 )     (3 )
Miscellaneous items, net
    (2 )     (1 )
Depreciation and amortization increases primarily due to increased depreciable assets, partially offset by lower depreciation rates
    (4 )     (2 )
Higher property taxes due to increased plant in service
    (4 )     (2 )
Miscellaneous items, net
          (2 )
 
           
Net decrease in net income
  $ (53 )   $ (33 )
 
           
     Regulated Electricity Revenues
     Regulated electricity revenues were $49 million higher for the three months ended March 31, 2006 compared with the prior-year period primarily as a result of:
    a $19 million increase in retail revenues related to customer growth, excluding weather effects;
 
    an $18 million increase in revenues related to the implementation of the February 1, 2006 PSA adjustor which has no earnings effect due to the offset from amortization of deferred fuel in fuel and purchased power expense;
 
    a $12 million increase in Off-System Sales primarily resulting from sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in regulated electricity in accordance with the APS retail rate case settlement;
 
    a $7 million increase in retail revenues due to a price increase effective April 1, 2005;
 
    a $4 million decrease in retail revenues related to weather; and
 
    a $3 million decrease due to miscellaneous factors.

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     Marketing and Trading Revenues
     Marketing and trading revenues were $13 million lower for the three months ended March 31, 2006 compared with the prior-year period primarily as a result of:
    a $15 million decrease in energy trading revenues on realized sales of electricity primarily due to lower delivered electricity prices and lower volumes;
 
    a $14 million increase in mark-to-market gains on contracts for future delivery due to changes in forward prices; and
 
    a $12 million decrease in Off-System Sales due to the absence of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in regulated electricity in accordance with the APS retail rate case settlement.
ARIZONA PUBLIC SERVICE COMPANY – LIQUIDITY AND CAPITAL RESOURCES
     Contractual Obligations
     APS’ future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2005 Form 10-K with the exception of our aggregate:
    fuel and purchased power commitments, which increased from approximately $1.7 billion at December 31, 2005 to $2.9 billion at March 31, 2006 as follows (in billions):
                 
2006   2007-2008   2009-2010   Thereafter   Total
$0.3
  $0.5   $0.4   $1.7   $2.9
     See Note 4 for a list of APS’ payments due on total long-term debt and capitalized lease requirements.
FORWARD-LOOKING STATEMENTS
     This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the 2005 Form 10-K, these factors include, but are not limited to:
    state and federal regulatory and legislative decisions and actions, including the outcome and timing of APS’ retail rate proceedings pending before the ACC;
 
    the timely recovery of PSA deferrals;

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    the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition;
 
    the outcome of regulatory, legislative and judicial proceedings, both current and future, relating to the restructuring;
 
    market prices for electricity and natural gas;
 
    power plant performance and outages;
 
    transmission outages and constraints;
 
    weather variations affecting local and regional customer energy usage;
 
    customer growth and energy usage;
 
    regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile fuel and purchased power costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;
 
    the cost of debt and equity capital and access to capital markets;
 
    current credit ratings remaining in effect for any given period of time;
 
    our ability to compete successfully outside traditional regulated markets (including the wholesale market);
 
    the performance of our marketing and trading activities due to volatile market liquidity and any deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);
 
    changes in accounting principles generally accepted in the United States of America and the interpretation of those principles;
 
    the performance of the stock market and the changing interest rate environment, which affect the amount of required contributions to Pinnacle West’s pension plan and APS’ nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits;
 
    technological developments in the electric industry;
 
    the strength of the real estate market in SunCor’s market areas, which include Arizona, Idaho, New Mexico and Utah; and
 
    other uncertainties, all of which are difficult to predict and many of which are beyond the control of Pinnacle West and APS.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.
Item 4. CONTROLS AND PROCEDURES
     (a) Disclosure Controls and Procedures
     The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
     Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of March 31, 2006. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.
     APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of March 31, 2006. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.
     (b) Changes In Internal Control Over Financial Reporting
     The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
     No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended March 31, 2006 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

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Part II — OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
     See Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report in regard to pending or threatened litigation or other disputes.
Item 1A. RISK FACTORS
      In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in the 2005 Form 10-K, which could materially affect the business, financial condition or future results of APS and Pinnacle West. The risks described in the 2005 Form 10-K are not the only risks facing APS and Pinnacle West. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition and/or operating results of APS and Pinnacle West.
Item 5. OTHER INFORMATION
Construction and Financing Programs
     See “Liquidity and Capital Resources” in Part I, Item 2 of this report for a discussion of construction and financing programs of the Company and its subsidiaries.
Regulatory Matters
     See Note 5 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of regulatory developments.
Environmental Matters
     See “Environmental Matters – Superfund” in Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of a Superfund site.
     Navajo Nation Environmental Issues
     On May 18, 2005, APS, Salt River Project and the Navajo Nation executed a Voluntary Compliance Agreement (“VCA”) to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. See “Navajo Nation Environmental Issues” in Part I, Item 1 of the 2005 Form 10-K. On March 21, 2006, the EPA determined that the Navajo Nation was eligible for “treatment as a state” for the purpose of entering into a supplemental delegation agreement with the EPA to administer the Clean Air Act Title V, Part 71 federal permit program over Four Corners. The EPA entered into the supplemental delegation agreement with the Navajo Nation on the same day. Because the EPA’s approval was consistent with the requirements of the VCA, APS sought dismissal of the pending litigation in the Navajo Nation Supreme Court and the pending litigation in the Navajo Nation District Court to the extent the claims relate to the Clean Air Act, and the Courts have dismissed the claims accordingly. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

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Item 6. EXHIBITS
     (a) Exhibits
         
Exhibit No.   Registrant(s)   Description
12.1
  Pinnacle West   Ratio of Earnings to Fixed Charges
 
       
12.2
  APS   Ratio of Earnings to Fixed Charges
 
       
12.3
  Pinnacle West   Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
 
       
31.1
  Pinnacle West   Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
 
       
31.2
  Pinnacle West   Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
 
       
31.3
  APS   Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
 
       
31.4
  APS   Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
 
       
32.1
  Pinnacle West   Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
       
32.2
  APS   Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
       
99.1
  Pinnacle West   Reconciliation of Operating Income to Gross Margin
 
       
99.2
  APS   Reconciliation of Operating Income to Gross Margin

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     In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:
                 
Exhibit               Date
No.   Registrant(s)   Description   Previously Filed as Exhibita   Effective
3.1
  Pinnacle West   Articles of Incorporation, restated as of July 29, 1988   19.1 to Pinnacle West’s September 1988 Form 10-Q Report, File No. 1-8962   11-14-88
 
               
3.2
  Pinnacle West   Pinnacle West Capital Corporation Bylaws, amended as of December 14, 2005   3.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473   12-15-05
 
               
3.3
  APS   Articles of Incorporation, restated as of May 25, 1988   4.2 to APS’ Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473   9-29-93
 
               
3.4
  APS   Arizona Public Service Company Bylaws, amended as of June 23, 2004   3.1 to APS’ June 30, 2004 Form 10-Q Report, File No. 1-4473   8-9-04
 
a Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
    PINNACLE WEST CAPITAL CORPORATION
     (Registrant)
 
       
Dated: May 9, 2006
  By:   /s/ Donald E. Brandt
 
       
 
      Donald E. Brandt
 
      Executive Vice President and Chief
 
      Financial Officer
 
      (Principal Financial Officer
 
      and Officer Duly Authorized to sign this Report)
 
       
    ARIZONA PUBLIC SERVICE COMPANY
     (Registrant)
 
       
Dated: May 9, 2006
  By:   /s/ Donald E. Brandt
 
       
 
      Donald E. Brandt
 
      Executive Vice President and Chief
 
      Financial Officer
 
      (Principal Financial Officer and
 
      Officer Duly Authorized to sign this Report)

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Index to Exhibits
         
Exhibit No.   Registrant(s)   Description
12.1
  Pinnacle West   Ratio of Earnings to Fixed Charges
 
       
12.2
  APS   Ratio of Earnings to Fixed Charges
 
       
12.3
  Pinnacle West   Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
 
       
31.1
  Pinnacle West   Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
 
       
31.2
  Pinnacle West   Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
 
       
31.3
  APS   Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
 
       
31.4
  APS   Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
 
       
32.1
  Pinnacle West   Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
       
32.2
  APS   Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
       
99.1
  Pinnacle West   Reconciliation of Operating Income to Gross Margin
 
       
99.2
  APS   Reconciliation of Operating Income to Gross Margin

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