e10vq
Table of Contents

 
 
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-Q
(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, 2007
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.
 
  PINNACLE WEST CAPITAL CORPORATION    
1-8962
  (an Arizona corporation)   86-0512431
 
  400 North Fifth Street, P.O. Box 53999    
 
  Phoenix, Arizona 85072-3999    
 
  (602) 250-1000    
         
 
  ARIZONA PUBLIC SERVICE COMPANY    
1-4473
  (an Arizona corporation)   86-0011170
 
  400 North Fifth Street, P.O. Box 53999    
 
  Phoenix, Arizona 85072-3999    
 
  (602) 250-1000    
     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 þ   No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.
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, 2007: 100,237,583
ARIZONA PUBLIC SERVICE COMPANY
  Number of shares of common stock, $2.50 par value, outstanding as of May 3, 2007: 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  
Part I         4  
    Item 1.       4  
            4  
            32  
    Item 2.       41  
    Item 3.       60  
    Item 4.       60  
Part II         61  
    Item 1.       61  
    Item 1A.       61  
    Item 5.       61  
    Item 6.       63  
Signatures         65  
 EX-10.1
 EX-10.2
 EX-12.1
 EX-12.2
 EX-12.3
 EX-31.1
 EX-31.2
 EX-31.3
 EX-31.4
 EX-32.1
 EX-32.2
 EX-99.1
 EX-99.2

 


Table of Contents

GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
ALJ – Administrative Law Judge
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
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
FIN – FASB Interpretation Number
Fitch – Fitch, Inc.
Four Corners – Four Corners Power Plant
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
kWh – kilowatt-hour, one thousand watts per hour
Moody’s – Moody’s Investors Service
MWh – megawatt-hour, one million watts per hour
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
Note – a Note to Pinnacle West’s Condensed Consolidated Financial Statements in Item 1 of this report
NRC – United States Nuclear Regulatory Commission
OCI – other comprehensive income
Off-System Sales – sales of electricity from generation owned or contracted 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, dissolved as of August 31, 2006

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Pinnacle West Marketing & Trading – Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company
PRP – potentially responsible parties under Superfund
PSA – power supply adjustor
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
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
2006 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2006
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,  
    2007     2006  
OPERATING REVENUES
               
Regulated electricity segment
  $ 536,051     $ 466,126  
Real estate segment
    77,250       107,854  
Marketing and trading
    72,471       85,002  
Other revenues
    9,363       11,224  
 
           
Total
    695,135       670,206  
 
           
OPERATING EXPENSES
               
Regulated electricity segment fuel and purchased power
    203,353       157,395  
Real estate segment operations
    61,443       71,330  
Marketing and trading fuel and purchased power
    57,944       74,175  
Operations and maintenance
    171,578       178,427  
Depreciation and amortization
    89,621       87,621  
Taxes other than income taxes
    34,719       35,573  
Other expenses
    8,488       8,522  
 
           
Total
    627,146       613,043  
 
           
OPERATING INCOME
    67,989       57,163  
 
           
OTHER
               
Allowance for equity funds used during construction
    4,444       3,801  
Other income (Note 14)
    4,512       5,467  
Other expense (Note 14)
    (6,353 )     (4,541 )
 
           
Total
    2,603       4,727  
 
           
INTEREST EXPENSE
               
Interest charges
    50,992       47,526  
Capitalized interest
    (4,807 )     (4,024 )
 
           
Total
    46,185       43,502  
 
           
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    24,407       18,388  
INCOME TAXES
    8,609       6,793  
 
           
INCOME FROM CONTINUING OPERATIONS
    15,798       11,595  
INCOME FROM DISCONTINUED OPERATIONS
               
Net of income tax expense of $479 and $557 (Note 17)
    732       860  
 
           
NET INCOME
  $ 16,530     $ 12,455  
 
           
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC
    100,045       99,115  
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED
    100,622       99,449  
 
               
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
               
Income from continuing operations – basic
  $ 0.16     $ 0.12  
Net income – basic
    0.17       0.13  
Income from continuing operations – diluted
    0.16       0.12  
Net income – diluted
    0.16       0.13  
DIVIDENDS DECLARED PER SHARE
  $ 0.525     $ 1.00  
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,  
    2007     2006  
ASSETS
               
 
               
CURRENT ASSETS
               
Cash and cash equivalents
  $ 121,253     $ 87,210  
Investment in debt securities
          32,700  
Customer and other receivables
    371,467       501,628  
Allowance for doubtful accounts
    (5,165 )     (5,597 )
Materials and supplies (at average cost)
    137,357       125,802  
Fossil fuel (at average cost)
    24,856       21,973  
Deferred income taxes
          982  
Assets from risk management and trading activities (Note 10)
    245,458       641,040  
Assets held for sale
    16,714        
Other current assets
    59,162       68,924  
 
           
Total current assets
    971,102       1,474,662  
 
           
 
               
INVESTMENTS AND OTHER ASSETS
               
Real estate investments – net
    533,176       526,008  
Assets from long-term risk management and trading activities (Note 10)
    152,271       167,211  
Decommissioning trust accounts (Note 18)
    349,470       343,771  
Other assets
    110,938       111,388  
 
           
Total investments and other assets
    1,145,855       1,148,378  
 
           
 
               
PROPERTY, PLANT AND EQUIPMENT
               
Plant in service and held for future use
    11,257,974       11,154,919  
Less accumulated depreciation and amortization
    3,852,033       3,797,475  
 
           
Net
    7,405,941       7,357,444  
Construction work in progress
    420,598       368,284  
Intangible assets, net of accumulated amortization
    90,251       96,100  
Nuclear fuel, net of accumulated amortization
    69,539       60,100  
 
           
Total property, plant and equipment
    7,986,329       7,881,928  
 
           
 
               
DEFERRED DEBITS
               
Deferred fuel and purchased power regulatory asset (Note 5)
    117,795       160,268  
Other regulatory assets
    625,480       686,016  
Other deferred debits (Note 8)
    162,396       104,691  
 
           
Total deferred debits
    905,671       950,975  
 
           
 
               
TOTAL ASSETS
  $ 11,008,957     $ 11,455,943  
 
           
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,  
    2007     2006  
LIABILITIES AND COMMON STOCK EQUITY
               
 
               
CURRENT LIABILITIES
               
Accounts payable
  $ 226,649     $ 346,047  
Accrued taxes (Note 8)
    317,250       263,935  
Accrued interest
    43,003       48,746  
Short-term borrowings
    71,050       35,750  
Current maturities of long-term debt
    61,428       1,596  
Customer deposits
    72,382       70,168  
Deferred income taxes
    10,744        
Liabilities from risk management and trading activities (Note 10)
    148,827       558,195  
Other current liabilities
    139,552       134,123  
 
           
Total current liabilities
    1,090,885       1,458,560  
 
           
 
               
LONG-TERM DEBT LESS CURRENT MATURITIES
    3,186,998       3,232,633  
 
           
 
               
DEFERRED CREDITS AND OTHER
               
Deferred income taxes
    1,232,825       1,225,798  
Regulatory liabilities
    646,424       635,431  
Liability for asset retirements
    270,264       268,389  
Liabilities for pension and other postretirement benefits (Note 6)
    600,358       588,852  
Liabilities from long-term risk management and trading activities (Note 10)
    108,048       171,170  
Unamortized gain – sale of utility plant
    40,038       41,182  
Other
    384,195       387,812  
 
           
Total deferred credits and other
    3,282,152       3,318,634  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (NOTES 5, 8, 12, 13 and 15)
               
 
               
COMMON STOCK EQUITY Common stock, no par value
    2,121,070       2,114,550  
Treasury stock
    (750 )     (449 )
 
           
Total common stock
    2,120,320       2,114,101  
 
           
Accumulated other comprehensive income (loss) (Note 11):
               
Pension and other postretirement benefits
    (19,110 )     (19,263 )
Derivative instruments
    66,606       31,531  
 
           
Total accumulated other comprehensive income
    47,496       12,268  
 
           
Retained earnings
    1,281,106       1,319,747  
 
           
Total common stock equity
    3,448,922       3,446,116  
 
           
 
               
TOTAL LIABILITIES AND COMMON STOCK EQUITY
  $ 11,008,957     $ 11,455,943  
 
           
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,  
    2007     2006  
CASH FLOWS FROM OPERATING ACTIVITIES
               
Net Income
  $ 16,530     $ 12,455  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization including nuclear fuel
    98,719       95,072  
Deferred fuel and purchased power
    (26,293 )     (14,538 )
Deferred fuel and purchased power amortization
    68,766       17,808  
Allowance for equity funds used during construction
    (4,444 )     (3,801 )
Deferred income taxes
    (12,752 )     1,757  
Change in mark-to-market valuations
    (5,494 )     9,305  
Changes in current assets and liabilities:
               
Customer and other receivables
    149,097       129,940  
Materials, supplies and fossil fuel
    (14,438 )     4,186  
Other current assets
    4,525       (7,537 )
Accounts payable
    (124,785 )     (124,577 )
Collateral
    (303 )     (170,690 )
Other current liabilities
    21,242       62,653  
Proceeds from the sale of real estate assets
    16,824       7,884  
Real estate investments
    (24,617 )     (28,670 )
Change in risk management and trading – assets
    54,689       67,984  
Change in risk management and trading – liabilities
    (480 )     (66,096 )
Change in other long-term assets
    (11,900 )     (2,247 )
Change in other long-term liabilities
    9,695       12,169  
 
           
Net cash flow provided by operating activities
    214,581       3,057  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES
               
Capital expenditures
    (206,083 )     (167,367 )
Capitalized interest
    (4,807 )     (4,024 )
Proceeds from the sale of Silverhawk
          207,620  
Purchases of investment securities
    (36,525 )     (269,526 )
Proceeds from sale of investment securities
    69,225       269,526  
Proceeds from nuclear decommissioning trust sales
    63,490       33,743  
Investment in nuclear decommissioning trust
    (68,675 )     (38,929 )
Other
    (626 )     654  
 
           
Net cash flow provided by (used for) investing activities
    (184,001 )     31,697  
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES
               
Issuance of long-term debt
    53,257       206,848  
Repayment of long-term debt
    (39,305 )     (39,587 )
Short-term borrowings and payments – net
    35,300       (70 )
Dividends paid on common stock
    (52,495 )     (49,608 )
Common stock equity issuance
    7,613       5,065  
Other
    (907 )     3,450  
 
           
Net cash flow provided by financing activities
    3,463       126,098  
 
           
 
               
NET INCREASE IN CASH AND CASH EQUIVALENTS
    34,043       160,852  
 
               
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    87,210       154,003  
 
           
 
               
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 121,253     $ 314,855  
 
           
Supplemental disclosure of cash flow information
               
Cash paid during the period for:
               
Income taxes paid, net of refunds
  $ 38,980     $ (40 )
Interest paid, net of amounts capitalized
  $ 50,703     $ 25,526  
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

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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 subsidiaries: APS, Pinnacle West Energy (dissolved as of August 31, 2006), APS Energy Services, SunCor, El Dorado and Pinnacle West Marketing & Trading. 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 condensed certain prior year amounts on our condensed consolidated statements of cash flows to conform to current year presentations.
2.   Condensed Consolidated Financial Statements
     Our unaudited condensed consolidated financial statements reflect all adjustments that 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 2006 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 interim periods. For these reasons, results for interim periods do not necessarily represent results to be expected for the year.
4.   Changes in Liquidity
     On January 4, 2007, the FERC issued an order permitting Pinnacle West to transfer its market-based rate tariff and wholesale power sales agreements to a newly-created Pinnacle West subsidiary, Pinnacle West Marketing & Trading. Pinnacle West completed the transfer on February 1, 2007, which resulted in Pinnacle West no longer being a public utility under the Federal Power Act. As a result, Pinnacle West is no longer subject to FERC jurisdiction in connection with its issuance of securities or its incurrence of long-term debt.
     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, 2007:

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                 
    Consolidated        
Year
  Pinnacle West     APS  
2007
  $ 2     $ 1  
2008
    193       1  
2009
    1       1  
2010
    224       224  
2011
    578       401  
Thereafter
    2,260       2,260  
 
           
Total
  $ 3,258     $ 2,888  
 
           
5.   Regulatory Matters
APS General Rate Case
     On December 15, 2006, hearings concluded in APS’ general rate case before the ACC. APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues, designed to recover the following (dollars in millions):
                 
    Annual        
    Revenue     Percentage  
    Increase     Increase  
Increased fuel and purchased power
  $ 314.4       14.8 %
Capital structure update
    98.3       4.6 %
Rate base update, including acquisition of
               
Sundance Plant
    46.2       2.2 %
Pension funding
    41.3       1.9 %
Other items
    (65.6 )     (3.1 )%
 
           
 
               
Total increase
  $ 434.6       20.4 %
 
           
     The request is based on (a) a rate base of $4.5 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.0325 per kWh based on estimated 2007 prices; and (c) a 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). If the ACC approves the requested base rate increase for fuel and purchased power costs, subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs would be recovered in base rates. See “Power Supply Adjustor” below.
     APS has also suggested three additional measures for the ACC’s consideration to improve APS’ financial metrics while benefiting APS’ customers in the long run:
    Allowing accelerated depreciation to address the large imbalance between APS’ capital expenditures (estimated to average more than $950 million per year from 2007 through 2009) and its recovery of those expenses (in discussing this measure, APS assumed an increase of $50 million per year in allowed depreciation expense, which would increase APS’ revenue requirement by that same amount);

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
    Placing generation and distribution construction work in progress (“CWIP”) in rate base (in discussing this measure, APS assumed the inclusion of its June 30, 2006 CWIP balance of $261 million in rate base, which would increase APS’ revenue requirement by about $33 million); and
 
    Approving an “attrition adjustment” to provide APS a reasonable opportunity to earn an authorized return on equity given overall cost increases and higher levels of construction needed to accommodate ongoing customer growth (APS suggested a minimum attrition adjustment that would increase the return on equity by 1.7% to 4.1%).
     The following table summarizes key rate case positions of APS, the ACC staff and the Arizona Residential Utility Consumer Office (“RUCO”), which the Arizona legislature established to represent the interests of residential utility consumers before the ACC:
                                                 
    APS (a)     ACC Staff (b)     RUCO (b)  
    Annual             Annual             Annual        
    Revenue     Percentage     Revenue     Percentage     Revenue     Percentage  
    Increase     Increase     Increase     Increase     Increase     Increase  
Annual revenue increase (decrease)
                                               
Increased fuel and purchased power
  $ 314.4       14.8 %   $ 193.5       9.2 %   $ 280.0       13.2 %
Non-fuel components
    120.2       5.6 %     (1.0 )     (0.1 )%     (68.0 )     (3.2 )%
 
                                   
Total
  $ 434.6       20.4 %   $ 192.5       9.1 %   $ 212.0       10.0 %
 
                                   
 
                                               
Base fuel rate (¢kWh)
    3.25 ¢             2.80 ¢             3.12 ¢        
 
                                               
Return on equity
    11.5 %             10.25 %             9.25 %        
 
                                               
Capital structure
                                               
Long-term debt
    45 %             45 %             50 %        
Common equity
    55 %             55 %             50 %        
 
                                               
Rate base
  $4.5 billion           $4.5 billion           $4.5 billion        
 
                                               
Test year ended
    9/30/2005               9/30/2005               9/30/2005          
 
(a)   APS rejoinder testimony (10/4/06).
 
(b)   Final position per post-hearing brief and/or final schedules (1/22/07). The ACC staff has also recommended that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.
     Other intervenors in the rate case include Arizonans for Electric Choice and Competition (“AECC”), a business coalition that advocates on behalf of retail electric customers in Arizona; and

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Phelps Dodge Mining Company (“Phelps Dodge”). In jointly-filed testimony, AECC and Phelps Dodge recommended that the ACC reduce APS’ requested annual increase by at least $134 million.
ALJ Recommended Order
     On April 27, 2007, an ACC ALJ issued a recommended order in connection with the rate case and APS’ application to recover through a PSA surcharge approximately $45 million of deferrals related to unplanned 2005 Palo Verde outages. See “Power Supply Adjustor – PSA Deferrals Related to Unplanned Palo Verde Outages” below.
     The ALJ recommended an increase of approximately $286 million, or 13.5%, in APS’ annual base retail revenues, which includes a fuel-related increase of approximately $280 million and non-fuel related increases of approximately $6 million. The ALJ recommended that the rate increase take effect June 1, 2007, at which time the interim PSA adjustor approved on May 1, 2006 would terminate. See “Interim Rate Increase” below. The ALJ’s recommended rate increase is based on a return on equity of 10.75%; a 45%/55% long-term debt/common equity capital structure; a weighted-average cost of capital of 8.32%; an original cost rate base of $4.4 billion; and a base rate for fuel and purchased power costs of $0.0312 per kWh.
     The ALJ recommended various modifications to the PSA, including the following: (a) the annual PSA adjustor would be established based on projected, rather than historical, fuel and purchased power costs; (b) the 90/10 sharing arrangement under which APS absorbs 10% of retail fuel and purchased power costs above the base rate and retains 10% of the benefit below the base rate would be modified to exclude certain costs, such as renewable energy resources and the fixed element of long-term purchase power agreements acquired through competitive procurement; (c) 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 per kWh limit to changes in the adjustor rate in any one year would remain in effect; and (d) there would not be a preset annual limit on the amount of fuel and purchased power costs that could be recovered through base rates and the PSA. The ALJ recommended that the modified PSA take effect June 1, 2007 based on the difference between APS’ proposed 2007 projected fuel and purchased power costs of $0.0325 per kWh and the base fuel rate of $0.0312 per kWh.
     The ALJ recommended that the ACC not adopt any of APS’ additional suggestions described above to improve APS’ financial metrics (accelerated depreciation, inclusion of construction work in process in rate base, and an attrition adjustment).
     The ALJ recommended (a) the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the PSA deferrals related to unplanned 2005 Palo Verde outages and (b) the recovery by APS of the balance of the PSA deferrals (approximately $34 million) over a twelve-month period through a temporary PSA surcharge to be effective concurrently with the implementation of new rates. As of May 1, 2007, these deferrals totaled approximately $48 million, including accrued interest. The ALJ also recommended that the ACC require APS and the ACC staff to develop “nuclear performance standards” for the ACC to consider in a separate proceeding. See “PSA Deferrals Related to Palo Verde Unplanned Outages” below.

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     APS and other parties to the rate case may file exceptions to the recommended order no later than May 15, 2007. APS is currently evaluating the recommended order and expects to file its exceptions to the ALJ’s recommendations by that date. After the exceptions have been filed by APS and the other parties, the ACC will then consider the ALJ’s recommended order and the exceptions. We cannot predict the timing or the outcome of this rate case or the resulting levels of regulated revenues.
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 was 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:
    authorized an interim PSA adjustor, effective May 1, 2006, that resulted in an interim retail rate increase of approximately 8.3% designed to recover approximately $138 million of fuel and purchased power costs incurred in 2006 (this interim adjustor, combined with the $15 million PSA surcharge approved by the ACC (see “Surcharge for Certain 2005 PSA Deferrals” below), resulted in a rate increase of approximately 9.0% designed to recover approximately $149 million of fuel and purchased power costs during 2006);
 
    provided 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” (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below);
 
    encouraged 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”;
 
    affirmed 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
 
    encouraged 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.”
     On December 8, 2006, the ACC approved APS’ request to continue the interim PSA adjustor until rates become effective as a result of the general rate case.

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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. Such adjustments are to be implemented by use of PSA adjustor rates and PSA surcharges. 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 records 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 annual adjustor rate 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;
 
    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 adjustment is made annually each February 1st and goes into effect automatically unless suspended by the ACC;
 
    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.
     2007 PSA Annual Adjustor
     The annual adjustor rate is set for twelve-month periods beginning February 1 of each year. The current PSA annual adjustor rate was set at $0.003987 per kWh effective February 1, 2007, down slightly from the maximum $0.004 annual adjustor rate effective February 1, 2006. The new adjustor rate (a) essentially maintains the approximate 5% retail rate increase that took effect February 1, 2006 as a result of the 2006 PSA Annual Adjustor and

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which expired on February 1, 2007 and (b) is designed to recover approximately $109 million of deferred fuel and purchased power costs over the twelve-month period that began February 1, 2007.
     Surcharge for Certain 2005 PSA Deferrals
     On April 12, 2006, the ACC approved APS’ request to recover $15 million of 2005 PSA deferrals over a twelve-month period beginning May 2, 2006, representing a temporary rate increase of approximately 0.7%. Approximately $45 million of 2005 PSA deferrals remain subject to a pending application (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below).
     PSA Deferrals Related to Unplanned Palo Verde Outages
     On February 2, 2006, APS filed with the ACC an application to recover approximately $45 million (plus interest) 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. During the course of the pending general rate case, the ACC staff recommended that the ACC disallow approximately $16 million ($10 million after income taxes) of the $45 million request. The ACC staff’s report alleges that four of the eleven Palo Verde outages in 2005 were “avoidable,” three of which resulted in the recommended disallowance. The report also finds, among other things, that:
    Three of the outages were due to “faulty or defective vendor supplied equipment” and concludes that APS’ actions were not imprudent in connection with these outages. The report recommends, however, that the ACC evaluate “the degree to which APS has sought appropriate legal or other remedies” in connection with these outages and that APS “be given the opportunity to demonstrate the steps that it has taken in this regard.”
 
    “Additional investigation will be needed to determine the cause of and responsibility for” the Palo Verde Unit 1 outage resulting from vibration levels in one of the Unit’s shutdown cooling lines.
     The report also recommends that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.
     APS disagrees with, and has contested, the report’s recommendation that the ACC disallow a portion of the $45 million of PSA deferrals. At the request of the ACC staff, this matter is being addressed by the ACC as part of APS’ pending general rate case. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of these deferrals. See “ALJ Recommended Order” above. APS believes the expenses in question were prudently incurred and, therefore, are recoverable.
     As noted under “Interim Rate Increase” above, the ACC has directed the ACC staff to conduct a “prudence audit” of unplanned 2006 Palo Verde outage costs. This prudence review has not yet been completed. PSA deferrals related to these 2006 outages are estimated to be about $79 million through December 31, 2006. APS believes these expenses were prudently incurred and, therefore, are recoverable.

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     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 per kWh limit to changes in the adjustor rate in any one year would remain in effect;
 
    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; and
 
    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.
     The ACC staff has recommended the following potential changes to the PSA:
    Establishing the PSA annual adjustor, beginning in 2007, based on projected fuel costs rather than historical fuel costs; and
 
    Removing all existing limitations on fuel cost recovery, including the 90/10 sharing arrangement.
     The ALJ in the rate case has recommended various modifications to the PSA. See “ALJ Recommended Order” above.
     PSA Balance
     The following table shows the changes in the deferred fuel and purchase power regulatory asset for the three months ended March 31, 2007 and 2006 (dollars in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Beginning balance
  $ 160     $ 173  
Deferred fuel and purchased power costs-current period
    25       13  
Interest on deferred fuel
    2       1  
Amounts recovered through revenues
    (69 )     (18 )
 
           
Ending balance
  $ 118     $ 169  
 
           
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. On February 13, 2006, the FERC increased this price cap to $400 per MWh for prospective sales. Sales at prices above the cap must be justified and are subject to potential refund. We do not expect this price cap to have a material impact on our financial statements.
     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 their 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 “April 17 Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding 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 April 17 Order, the Pinnacle West Companies must charge cost-based rates, rather than market-based rates, in the APS control area for sales occurring after the date of the order, April 17, 2006. The Pinnacle West Companies are required to refund any amounts collected that exceed the default cost-based rates for all market rate sales within the APS control area from February 27, 2005 to April 17, 2006.
     The Pinnacle West Companies filed a Request for Rehearing and Clarification of the April 17 Order on May 17, 2006 and submitted a supplemental compliance filing on July 28, 2006. On December 21, 2006, FERC issued an order granting clarification and provided additional details on

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what steps the Pinnacle West Companies could take to correct the transmission import study previously submitted. The Pinnacle West Companies complied with this order and filed additional transmission studies and generation market power analyses on February 20, 2007.
     Based upon an analysis of the April 17 Order and preliminary calculations of the refund obligations, at this time, neither Pinnacle West nor APS believes that the April 17 Order will have a material adverse effect on its financial position, results of operations or cash flows.
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, 2007 and 2006. 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 Ended     Three Months Ended  
    March 31,     March 31,  
    2007     2006     2007     2006  
Service cost-benefits earned during the period
  $ 14     $ 15     $ 6     $ 7  
Interest cost on benefit obligation
    27       29       10       13  
Expected return on plan assets
    (29 )     (30 )     (12 )     (13 )
Amortization of:
                               
Transition obligation
                1       1  
Prior service cost
    1       1              
Net actuarial loss
    4       7       2       3  
 
                       
Net periodic benefit cost
  $ 17     $ 22     $ 7     $ 11  
 
                       
Portion of cost charged to expense
  $ 8     $ 9     $ 3     $ 5  
 
                       
APS’ share of costs charged to expense
  $ 7     $ 8     $ 3     $ 4  
 
                       
Contributions
     The contribution to our pension plan in 2007 is estimated to be approximately $22 million, and the contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $21 million. APS’ share is approximately 97% of both plans.
7.   Business Segments
     Pinnacle West’s two principal business segments are:

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    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; and
 
    our real estate segment, which consists of SunCor’s real estate development and investment activities.
     Financial data for the three months ended March 31, 2007 and 2006 and at March 31, 2007 and December 31, 2006 by business segment is provided as follows (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Operating Revenues:
               
Regulated electricity
  $ 536     $ 466  
Real estate
    77       108  
Other
    82       96  
 
           
Total
  $ 695     $ 670  
 
           
 
               
Net Income (Loss):
               
Regulated electricity
  $ 4     $ (12 )
Real estate
    9       22  
Other
    4       3  
 
           
Total
  $ 17     $ 13  
 
           
                 
    As of     As of  
    March 31, 2007     December 31, 2006  
Assets:
               
Regulated electricity
  $ 10,056     $ 10,566  
Real estate
    619       591  
Other
    334       299  
 
           
Total
  $ 11,009     $ 11,456  
 
           
8.   Income Taxes
     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2007, it is expected that the IRS will finalize its examination and will issue a settlement on the tax accounting method change. At this time an estimate of the range of reasonably possible change in the uncertain tax position cannot be made. However, we do not expect the ultimate outcome of this examination to have a material

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adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows.
     We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.
     The total amount of unrecognized tax benefits recorded in accrued taxes as of January 1, 2007 was $186 million, of which $179 million related to APS. The majority of the unrecognized tax benefits relate to the 2001 tax return position described above. Included in the balance of unrecognized tax benefits at January 1, 2007 are approximately $5 million of tax positions for consolidated Pinnacle West that, if recognized, would decrease our effective tax rate. For APS, approximately $3 million would have the same effect.
     We continue to recognize potential accrued interest related to unrecognized tax benefits in the financial statements as income tax expense. As of January 1, 2007, the total amount of accrued interest expense related to uncertain tax positions was $54 million for consolidated Pinnacle West, which is included as a component of the $186 million unrecognized tax benefit noted above. APS’ share included in the total was approximately $53 million. Additionally, Pinnacle West has accrued $9 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS. The application of FIN 48 did not have a material impact for the quarter ended March 31, 2007.
     As of January 1, 2007, the tax year ending December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ending prior to December 31, 1999 may remain subject to examination by state taxing authorities.
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, 2007, APS would have been required to assume approximately $214 million of debt and pay the equity participants approximately $177 million.

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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 of March 31, 2007, we hedged exposures to the price variability of the power and gas commodities for a maximum of 4.8 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, 2007 and 2006 are comprised of the following (dollars in thousands):
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting
  $ 911     $ (178 )
Losses from the change in options’ time value excluded from measurement of effectiveness
          (18 )
Gains from the discontinuance of cash flow hedges
    314       434  
     During the next twelve months ending March 31, 2008, we estimate that a net gain of $76 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.
     The following tables summarize our assets and liabilities from risk management and trading activities at March 31, 2007 and December 31, 2006 (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
March 31, 2007   Assets     Assets     Liabilities     Other     (Liability)  
Regulated electricity:
                                       
Mark-to-market
  $ 82,204     $ 84,955     $ (42,134 )   $ (78,680 )   $ 46,345  
Margin account and options
    18,524             (1,671 )           16,853  
Marketing and trading:
                                       
Mark-to-market
    144,622       62,095       (92,192 )     (29,368 )     85,157  
Options, emission allowances and other – at cost
    108       5,221       (12,830 )           (7,501 )
 
                             
Total
  $ 245,458     $ 152,271     $ (148,827 )   $ (108,048 )   $ 140,854  
 
                             
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
December 31, 2006   Assets     Assets     Liabilities     Other     (Liability)  
Regulated electricity:
                                       
Mark-to-market
  $ 458,034     $ 96,892     $ (481,661 )   $ (135,056 )   $ (61,791 )
Margin account and options
    77,705             (2,228 )           75,477  
Marketing and trading:
                                       
Mark-to-market
    105,301       69,480       (61,553 )     (36,114 )     77,114  
Options and emission allowances – at cost
          839       (12,753 )           (11,914 )
 
                             
Total
  $ 641,040     $ 167,211     $ (558,195 )   $ (171,170 )   $ 78,886  
 
                             
     During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps in the regulated electricity segment. We historically presented the buy side and the sell side of such swaps at fair value gross on our consolidated balance sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset/liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $19 million at March 31, 2007 and an asset of $73 million at December 31, 2006 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 $5 million at March 31, 2007 and $10 million at December 31, 2006, and is included in other current assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $60 million at March 31, 2007 and $54 million at December 31, 2006, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.

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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 11% of Pinnacle West’s $398 million of risk management and trading assets as of March 31, 2007. 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, 2007 and 2006 are as follows (dollars in thousands):
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Net income
  $ 16,530     $ 12,455  
 
           
Other comprehensive income (loss):
               
Net unrealized gains (losses) on derivative instruments (a)
    62,560       (204,983 )
Net reclassification of realized gains to income (b)
    (5,013 )     (17,530 )
Reclassification of pension and other postretirement benefits to income
    251        
Income tax benefit (expense) related to items of other comprehensive income (loss)
    (22,570 )     86,891  
 
           
Total other comprehensive income (loss)
    35,228       (135,622 )
 
           
Comprehensive income (loss)
  $ 51,758     $ (123,167 )
 
           
 
(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.

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(b)   These amounts primarily include the reclassification of unrealized gains and losses to realized for contracted commodities delivered during the period.
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 at least 2017. 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 is currently pursuing that damages claim.
     APS currently estimates it will incur $147 million (in 2006 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, 2007, APS had a regulatory liability of $2.8 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.
     NRC Inspection
     In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator started but did not provide electrical output during routine inspections on July 25 and September 22, 2006.
     On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) for this matter. In connection with its finding, the NRC stated that it would “use the NRC Action Matrix to determine the most appropriate response and any increase in NRC oversight, or actions [APS needs] to take in response to the most recent performance deficiencies” and notify APS of its determination at a later date. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix, which will result in an enhanced NRC inspection regimen. APS continues to implement its plan to improve Palo Verde’s operational performance.

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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. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Various parties filed petitions for rehearing on this order. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. 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 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 was denied on July 31, 2006. On October 10, 2006, the State of California filed a motion to stay the issuance of the mandate (scheduled to be issued on November 2, 2006) until June 13, 2007. The request for stay was granted. 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 wholesale sales in 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 and oral argument was held on January 8, 2007. Although the FERC ruling in this matter is being appealed

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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 cost responsibility associated with the changed contractual obligations in a way that would be less favorable to APS than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS’ annual capacity cost could be increased by approximately $3 million per year after income taxes for the period September 2003 through December 2005. This appeal had been stayed pending further consideration by the FERC. On May 26, 2006, the FERC issued an Order on Remand affirming its earlier decision that there is no basis for modifying the settlement rates during the remaining term of the settlement. The party seeking appellate review is continuing to pursue an appeal of this issue and has therefore sought rehearing of the May 26, 2006 order. The FERC’s next status report is due to the DC Circuit Court of Appeals by August 7, 2007.
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

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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 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 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 program 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.

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     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 $18.1 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, 2007 and 2006 (dollars in thousands):
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Other income:
               
Interest income
  $ 3,413     $ 4,905  
SunCor other income (a)
    579       166  
Miscellaneous
    520       396  
 
           
Total other income
  $ 4,512     $ 5,467  
 
           
 
               
Other expense:
               
Non-operating costs (b)
  $ (3,311 )   $ (3,719 )
Investment losses – net
    (1,739 )     (31 )
Miscellaneous
    (1,303 )     (791 )
 
           
Total other expense
  $ (6,353 )   $ (4,541 )
 
           
 
(a)   Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.
 
(b)   As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).
15. Guarantees
     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to commodity energy products. 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 subsidiaries 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
     West’s current outstanding guarantees on behalf of its subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2007 are as follows (dollars in millions):
                                 
    Guarantees     Surety Bonds  
            Term             Term  
    Amount     (in years)     Amount     (in years)  
Parental:
                               
Pinnacle West Marketing & Trading
  $ 63       1     $        
APS Energy Services
    15       1       19       1  
 
                           
Total
  $ 78             $ 19          
 
                           
     At March 31, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in late 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, 2007, 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 $86 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, at March 31, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2007. 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; most significantly, 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, 2007 and 2006:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Basic earnings per share:
               
Income from continuing operations
  $ 0.16     $ 0.12  
Income from discontinued operations
    0.01       0.01  
 
           
Earnings per share – basic
  $ 0.17     $ 0.13  
 
           
 
               
Diluted earnings per share:
               
Income from continuing operations
  $ 0.16     $ 0.12  
Income from discontinued operations
          0.01  
 
           
Earnings per share – diluted
  $ 0.16     $ 0.13  
 
           
     Dilutive stock options and performance shares increased average common shares outstanding by approximately 577,000 shares and 334,000 shares for the three months ended March 31, 2007 and March 31, 2006, respectively.
     For the three-month period ended March 31, 2007, there were no outstanding options to purchase shares excluded from the computation of earnings per share because the options’ exercise prices were less than the average market price of the common shares. Options to purchase shares of common stock that were excluded from the computation of diluted earnings per share were 747,874 shares for the three-month period ended March 31, 2006.
17. Discontinued Operations
     SunCor (real estate segment) In 2006 and 2007, 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 contains SunCor’s revenue, income before income taxes and income after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2007 and 2006 (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Revenue
  $ 2     $ 1  
Income before income taxes
    1       1  
Income after income taxes
    1       1  
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 fixed income and 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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, 2007 and December 31, 2006 (dollars in millions):
                 
            Total Unrealized  
    Fair Value     Gains  
March 31, 2007
               
Equity securities
  $ 167     $ 63  
Fixed income securities
    182       3  
 
           
Total
  $ 349     $ 66  
 
           
 
               
December 31, 2006
               
Equity securities
  $ 164     $ 63  
Fixed income securities
    180       3  
 
           
Total
  $ 344     $ 66  
 
           
     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,
    2007   2006
Realized gains
  $ 1     $ 1  
Realized losses
    (1 )     (1 )
Proceeds from the sale of securities
    63       34  
     The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2007 is as follows (dollars in millions):
         
Fair Value   March 31, 2007  
Less than one year
  $ 15  
1 year - 5 years
    41  
5 years - 10 years
    41  
Greater than 10 years
    85  
 
     
Total
  $ 182  
 
     
19. New Accounting Standards
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance.

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     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance.
     See Note 8 for a discussion of FASB Interpretation No. 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial.

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CONDENSED STATEMENTS OF INCOME

(unaudited)
(dollars in thousands)
                 
    Three Months Ended  
    March 31,  
    2007     2006  
ELECTRIC OPERATING REVENUES
               
Regulated electricity
  $ 537,376     $ 467,222  
Marketing and trading
    884       9,647  
 
           
Total
    538,260       476,869  
 
           
 
               
OPERATING EXPENSES
               
Regulated electricity fuel and purchased power
    204,494       158,274  
Marketing and trading fuel and purchased power
    1,702       1,368  
Operations and maintenance
    165,934       173,353  
Depreciation and amortization
    87,876       86,311  
Income taxes
    3,143       (3,029 )
Other taxes
    34,522       35,548  
 
           
Total
    497,671       451,825  
 
           
OPERATING INCOME
    40,589       25,044  
 
           
 
               
OTHER INCOME (DEDUCTIONS)
               
Income taxes
    754       236  
Allowance for equity funds used during construction
    4,444       3,801  
Other income (Note S-3)
    4,433       4,806  
Other expense (Note S-3)
    (4,904 )     (3,680 )
 
           
Total
    4,727       5,163  
 
           
 
               
INTEREST DEDUCTIONS
               
Interest on long-term debt
    40,075       34,250  
Interest on short-term borrowings
    1,981       2,026  
Debt discount, premium and expense
    1,156       1,173  
Allowance for borrowed funds used during construction
    (2,213 )     (1,721 )
 
           
Total
    40,999       35,728  
 
           
 
               
NET INCOME (LOSS)
  $ 4,317     $ (5,521 )
 
           
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,  
    2007     2006  
ASSETS
               
 
               
UTILITY PLANT
               
Electric plant in service and held for future use
  $ 11,195,376     $ 11,094,868  
Less accumulated depreciation and amortization
    3,843,518       3,789,534  
 
           
Net
    7,351,858       7,305,334  
 
               
Construction work in progress
    419,639       365,704  
Intangible assets, net of accumulated amortization
    89,775       95,601  
Nuclear fuel, net of accumulated amortization
    69,539       60,100  
 
           
Total utility plant
    7,930,811       7,826,739  
 
           
 
               
INVESTMENTS AND OTHER ASSETS
               
Decommissioning trust accounts (Note 18)
    349,470       343,771  
Assets from long-term risk management and trading activities (Note S-1)
    84,955       96,892  
Other assets
    68,389       67,763  
 
           
Total investments and other assets
    502,814       508,426  
 
           
 
               
CURRENT ASSETS
               
Cash and cash equivalents
    102,564       81,870  
Investment in debt securities
          32,700  
Customer and other receivables
    303,790       410,436  
Allowance for doubtful accounts
    (3,834 )     (4,223 )
Materials and supplies (at average cost)
    137,357       125,802  
Fossil fuel (at average cost)
    24,856       21,973  
Assets from risk management and trading activities (Note S-1)
    105,278       539,308  
Deferred income taxes
    11,763       19,220  
Other current assets
    13,821       13,367  
 
           
Total current assets
    695,595       1,240,453  
 
           
 
               
DEFERRED DEBITS
               
Deferred fuel and purchased power regulatory asset (Note 5)
    117,795       160,268  
Other regulatory assets
    625,480       686,016  
Unamortized debt issue costs
    25,869       26,393  
Other (Note 8)
    131,319       65,397  
 
           
Total deferred debits
    900,463       938,074  
 
           
 
               
TOTAL ASSETS
  $ 10,029,683     $ 10,513,692  
 
           
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,  
    2007     2006  
LIABILITIES AND EQUITY
               
 
               
CAPITALIZATION
               
Common stock
  $ 178,162     $ 178,162  
Additional paid-in capital
    2,065,918       2,065,918  
Retained earnings
    924,434       960,405  
Accumulated other comprehensive income:
               
Derivative instruments
    34,150       2,988  
 
           
Common stock equity
    3,202,664       3,207,473  
Long-term debt less current maturities
    2,877,377       2,877,502  
 
           
Total capitalization
    6,080,041       6,084,975  
 
           
 
               
CURRENT LIABILITIES
               
Current maturities of long-term debt
    1,049       968  
Accounts payable
    136,800       223,417  
Accrued taxes (Note 8)
    425,641       381,444  
Accrued interest
    39,304       45,254  
Common dividends payable
    42,500        
Customer deposits
    64,571       61,900  
Liabilities from risk management and trading activities (Note S-1)
    51,962       490,855  
Other current liabilities
    71,404       74,728  
 
           
Total current liabilities
    833,231       1,278,566  
 
           
 
               
DEFERRED CREDITS AND OTHER
               
Deferred income taxes
    1,226,020       1,215,862  
Regulatory liabilities
    646,424       635,431  
Liability for asset retirements
    270,264       268,389  
Pension and other postretirement liabilities (Note 6)
    562,088       551,531  
Customer advances for construction
    74,684       71,211  
Unamortized gain – sale of utility plant
    40,038       41,182  
Liabilities from long-term risk management and trading activities (Note S-1)
    78,680       135,056  
Other
    218,213       231,489  
 
           
Total deferred credits and other
    3,116,411       3,150,151  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (NOTES 5, 8, 12, 13 and 15)
               
 
               
TOTAL LIABILITIES AND EQUITY
  $ 10,029,683     $ 10,513,692  
 
           
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,  
    2007     2006  
CASH FLOWS FROM OPERATING ACTIVITIES
               
Net income (loss)
  $ 4,317     $ (5,521 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depreciation and amortization including nuclear fuel
    96,974       93,762  
Deferred fuel and purchased power
    (26,293 )     (14,538 )
Deferred fuel and purchased power amortization
    68,766       17,808  
Allowance for equity funds used during construction
    (4,444 )     (3,801 )
Deferred income taxes
    (15,566 )     1,757  
Changes in mark-to-market valuations
    (3,507 )     974  
Changes in current assets and liabilities:
               
Customer and other receivables
    128,030       124,568  
Materials, supplies and fossil fuel
    (14,438 )     (1,101 )
Other current assets
    (2,112 )     4,892  
Accounts payable
    (92,004 )     (62,543 )
Accrued taxes
    6,673       30,343  
Collateral
    1,789       (150,640 )
Other current liabilities
    (6,533 )     32,231  
Change in risk management and trading – assets
    59,181       2,189  
Change in risk management and trading – liabilities
    (557 )     (65,131 )
Change in other long-term assets
    (21,108 )     (7,524 )
Change in other long-term liabilities
    6,284       11,366  
 
           
Net cash flow provided by operating activities
    185,452       9,091  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES
               
Capital expenditures
    (188,947 )     (140,185 )
Allowance for borrowed funds used during construction
    (2,213 )     (1,721 )
Purchases of investment securities
    (36,525 )     (122,025 )
Proceeds from sale of investment securities
    69,225       122,025  
Proceeds from nuclear decommissioning trust sales
    63,490       33,743  
Investment in nuclear decommissioning trust
    (68,675 )     (38,929 )
Other
    (826 )     (1,966 )
 
           
Net cash flow used for investing activities
    (164,471 )     (149,058 )
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES
               
Equity infusion
          210,000  
Dividends paid on common stock
          (42,500 )
Repayment and reacquisition of long-term debt
    (287 )     (821 )
 
           
Net cash flow provided by (used for) financing activities
    (287 )     166,679  
 
           
 
               
NET INCREASE IN CASH AND CASH EQUIVALENTS
    20,694       26,712  
 
               
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    81,870       49,933  
 
           
 
               
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 102,564     $ 76,645  
 
           
Supplemental disclosure of cash flow information:
               
Cash paid during the year for:
               
Income taxes, net of refunds
  $ 44,088     $  
Interest, net of amounts capitalized
  $ 45,793     $ 24,297  
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  
Income Taxes
  Note 8  
Variable Interest Entities
  Note 9  
Derivative and Energy Trading Accounting
  Note 10   Note S-1
Comprehensive Income (Loss)
  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  
New Accounting Standards
  Note 19  

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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 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, 2007, APS hedged exposures to these risks for a maximum of 4.8 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, 2007 and 2006 were comprised of the following (dollars in thousands):
                 
    Three Months Ended
    March 31,
    2007   2006
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting
  $ 911     $ (436 )
Losses from the change in options’ time value excluded from measurement of effectiveness
          (18 )
Gains from the discontinuance of cash flow hedges
    150       159  
     During the next twelve months ending March 31, 2008, APS estimates that a net gain of $39 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.
     The following tables summarize APS’ assets and liabilities from risk management and trading activities at March 31, 2007 and December 31, 2006 (dollars in thousands):

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
March 31, 2007   Assets     Assets     Liabilities     Other     (Liability)  
Regulated Electricity:
                                       
Mark-to-market
  $ 82,204     $ 84,955     $ (42,134 )   $ (78,680 )   $ 46,345  
Margin account and options
    18,524             (1,671 )           16,853  
Marketing and Trading:
                                       
Mark-to-market
    4,550             (7,845 )           (3,295 )
Options at cost
                (312 )           (312 )
 
                             
Total
  $ 105,278     $ 84,955     $ (51,962 )   $ (78,680 )   $ 59,591  
 
                             
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
December 31, 2006   Assets     Assets     Liabilities     Other     (Liability)  
Regulated Electricity:
                                       
Mark-to-market
  $ 458,034     $ 96,892     $ (481,661 )   $ (135,056 )   $ (61,791 )
Margin account and options
    77,705             (2,228 )           75,477  
Marketing and Trading:
                                       
Mark-to-market
    3,569             (6,654 )           (3,085 )
Options at cost
                (312 )           (312 )
 
                             
Total
  $ 539,308     $ 96,892     $ (490,855 )   $ (135,056 )   $ 10,289  
 
                             
     During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps in the regulated electricity segment. We historically presented the buy side and the sell side of such swaps at fair value gross on our consolidated balance sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset/liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $19 million at March 31, 2007 and $73 million at December 31, 2006 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, 2007 and $2 million was provided at December 31, 2006 and is included in other current assets on the Condensed Balance Sheets. Collateral provided to us by counterparties was $1 million at both March 31, 2007 and December 31, 2006, and is included in other current liabilities on the Condensed Balance Sheets.

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
S-2. Comprehensive Income (Loss)
     Components of APS’ comprehensive income (loss) for the three months ended March 31, 2007 and 2006 are as follows (dollars in thousands):
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Net income (loss)
  $ 4,317     $ (5,521 )
 
           
Other comprehensive income (loss):
               
Net unrealized gains (losses) on derivative instruments (a)
    50,545       (162,892 )
Net reclassification of realized losses (gains) to income (b)
    741       (10,116 )
Net income tax benefit (expense) related to items of other comprehensive income (loss)
    (20,124 )     67,560  
 
           
Total other comprehensive income (loss)
    31,162       (105,448 )
 
           
Comprehensive income (loss)
  $ 35,479     $ (110,969 )
 
           
 
(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, 2007 and 2006 (dollars in thousands):

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    Three Months Ended  
    March 31,  
    2007     2006  
Other income:
               
Interest income
  $ 3,347     $ 3,534  
Investment gains – net
    377       875  
Miscellaneous
    709       397  
 
           
Total other income
  $ 4,433     $ 4,806  
 
           
 
               
Other expense:
               
Non-operating costs (a)
  $ (3,233 )   $ (3,216 )
Asset dispositions
    (1,081 )     (196 )
Miscellaneous
    (590 )     (268 )
 
           
Total other expense
  $ (4,904 )   $ (3,680 )
 
           
 
(a)   As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

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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, these proceedings consist of:
    a general retail rate case pursuant to which APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues;
 
    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 that were deferred by APS in 2005 under the PSA and are subject to the ACC’s completion of an inquiry regarding the outages (this matter is now being addressed in the general retail rate case); and
 
    the ACC’s prudency review of amounts collected through the May 2, 2006 interim PSA adjustor (see “Interim Rate Increase” in Note 5) related to unplanned 2006 Palo Verde outages.
     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings. See discussion below in “Pinnacle West Consolidated – Factors Affecting our Financial Outlook – Subsidiaries.” 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 Marketing & Trading is the Company’s newly-formed marketing and trading subsidiary. Activity in this subsidiary began in February 2007. See Note 4.
     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. 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.

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     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’s two principal business segments are:
    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; and
 
    our real estate segment, which consists of SunCor’s real estate development and investment activities.
     The following table summarizes income from continuing operations by segment for the three months ended March 31, 2007 and 2006 and reconciles net income in total (dollars in millions):
                 
    Three Months Ended  
    March 31,  
    2007     2006  
Regulated electricity
  $ 4     $ (12 )
Real estate
    8       21  
Other (a)
    4       3  
 
           
Income from continuing operations
    16       12  
Discontinued operations – net of tax:
               
Real estate
    1       1  
 
           
Net income
  $ 17     $ 13  
 
           
 
(a)   Primarily marketing and trading activity.
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, 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 accounting principles generally accepted in the United States (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.
Deferred Fuel and Purchased Power Costs
     Our subsidiary, APS, settled its 2003 general retail rate case effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund

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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. See “Power Supply Adjustor” in Note 5.
     Since the inception of the PSA, APS has incurred substantially higher fuel and purchased power costs than those authorized for recovery through APS’ current base rates, primarily due to the use of higher cost resources and higher fuel prices, and has deferred those cost differences in accordance with the PSA. The balance of APS’ PSA accumulated unrecovered deferrals at March 31, 2007 was approximately $118 million. The recovery of PSA deferrals through ACC approved adjustors and surcharges recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses recorded as fuel and purchased power.
     APS recorded PSA deferrals of (a) $45 million related to replacement power costs in 2005 associated with unplanned Palo Verde outages and (b) $79 million related to replacement power costs in 2006 associated with unplanned outages or reduced power operations at Palo Verde. The PSA deferrals associated with these unplanned Palo Verde outages and reduced power operations are the subject of ACC prudence reviews. The ACC staff has completed its prudence review of 2005 unplanned outages and has recommended disallowance of $16 million of the 2005 costs. The recommendation is being considered as part of APS’ general rate case currently pending before the ACC. See “PSA Deferrals Related to Unplanned Palo Verde Outages” in Note 5. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the deferrals related to the unplanned 2005 Palo Verde outages. See “ALJ Recommended Order” in Note 5. Neither the ACC staff recommendation nor the ALJ recommendation changes management’s belief that the expenses in question were prudently incurred and, therefore, are recoverable. The prudence review of 2006 unplanned outages has not yet been completed.
Operating Results – Three-month period ended March 31, 2007 compared with three-month period ended March 31, 2006
     Our consolidated net income for the three months ended March 31, 2007 was $17 million compared with $13 million for the comparable prior-year period. Net income increased $4 million in the period-to-period comparison, reflecting the following changes in earnings by segment:
    Regulated Electricity Segment – Net income increased approximately $16 million primarily due to the effects of cooler weather on retail sales; higher retail sales due to customer growth; and lower operations and maintenance expense related to generation. In addition, higher fuel and purchased power costs were partially offset by the deferral of such costs in accordance with the PSA. See “Deferred Fuel and Purchased Power Costs” above.
 
    Real Estate Segment – Net income decreased approximately $13 million primarily due to lower sales of land parcels and residential property.
 
    Other miscellaneous items, net, increased approximately $1 million.

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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:
               
Effects of cooler weather on retail sales
  $ 13     $ 8  
Higher retail sales due to customer growth, excluding weather effects
    10       6  
Higher fuel and purchased power costs due to increased prices (see “Deferred Fuel and Purchased Power Costs” above)
    (14 )     (9 )
Increased deferred fuel and purchased power costs
    12       7  
Miscellaneous items, net
    3       3  
 
           
Net increase in regulated electricity segment gross margin
    24       15  
Lower real estate segment contribution primarily due to decreased sales of land parcels and residential property
    (21 )     (13 )
Operations and maintenance decreases primarily due to:
               
Generation costs, including fewer power plant maintenance outages
    4       2  
Miscellaneous items, net
    3       2  
Other miscellaneous items, net
    (4 )     (2 )
 
           
Net increase in net income
  $ 6     $ 4  
 
           
Regulated Electricity Segment Revenues
     Regulated electricity segment revenues were $70 million higher for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:
    a $51 million increase in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see “Deferred Fuel and Purchased Power Costs” above);
 
    an $18 million increase in retail revenues due to cooler weather;
 
    a $13 million increase in retail revenues related to customer growth, excluding weather effects;
 
    a $5 million decrease in Off-System Sales due to lower sales volumes; and
 
    a $7 million decrease due to miscellaneous factors.
Real Estate Segment Revenues
     Real estate segment revenues were $31 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:
    a $20 million decrease in residential sales due to a slowdown in the western United States residential real estate markets;

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    a $15 million decrease in revenue primarily due to a significant land parcel sale in 2006 without a comparable sale in 2007; and
 
    a $4 million increase due to miscellaneous factors.
Other Revenues
     Marketing and trading revenues were $13 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:
    an $11 million decrease from lower competitive retail sales volumes in California; and
 
    a $2 million decrease due to miscellaneous factors.
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, 2007 and estimated capital expenditures for the next three years (dollars in millions):
CAPITAL EXPENDITURES
                                 
    Three Months Ended     Estimated for the Year Ended  
    March 31,     December 31,  
    2007     2007     2008     2009  
APS
                               
Distribution
  $ 97     $ 362     $ 411     $ 459  
Transmission
    40       173       200       288  
Generation
    45       388       298       335  
Other (a)
    1       26       39       40  
 
                       
Subtotal
    183       949       948       1,122  
SunCor (b)
    39       131       101       100  
Other
    1       13       19       10  
 
                       
Total
  $ 223     $ 1,093     $ 1,068     $ 1,232  
 
                       
 
(a)   Primarily information systems and facilities projects.
 
(b)   Consists primarily of capital expenditures for residential 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

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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. Environmental expenditures are estimated at approximately $80 million to $100 million per year for 2007, 2008 and 2009. Generation also includes nuclear fuel expenditures of approximately $110 million for 2007, $40 million for 2008 and $100 million for 2009.
     The Palo Verde owners have approved the manufacture of one additional set of steam generators. These generators will be installed in Unit 3 and are scheduled for completion in the Fall of 2007 at an approximate cost of $70 million (APS’ share). Approximately $30 million of the Unit 3 steam generator costs have been incurred through March 31, 2007, with the remaining $40 million included 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 2006 Form 10-K, with the exception of our aggregate fuel and purchased power commitments, which increased from approximately $2.6 billion at December 31, 2006 to $2.8 billion at March 31, 2007 as follows (dollars in billions):
                                 
2007   2008-2009   2010-2011   Thereafter   Total
$0.5
  $ 0.5     $ 0.5     $ 1.3     $ 2.8  
     See Note 4 for a list of payments due on total long-term debt and capitalized lease requirements.
     Upon adoption of FIN 48, we are now required to include uncertain tax positions in our contractual obligation disclosure. We have uncertain tax positions of approximately $186 million and we expect to pay these in 2007. See Note 8.
     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, 2007, APS would have been required to assume approximately $214 million of debt and pay the equity participants approximately $177 million.

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     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, 2007 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 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 the 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   Fitch
Pinnacle West
           
Senior unsecured (a)
  Baa3 (P)   BB+ (prelim)   N/A
Commercial paper
  P-3   A-3   F-3
Outlook
  Negative   Stable   Stable
 
           
APS
           
Senior unsecured
  Baa2   BBB-   BBB
Secured lease obligation bonds
  Baa2   BBB-   BBB-
Commercial paper
  P-2   A-3   F-2
Outlook
  Negative   Stable   Stable
 
(a)   Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigns a provisional (P) rating and Standard & Poor’s assigns a preliminary (prelim) rating to the senior unsecured securities under such shelf registrations.
     Debt Provisions
     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. 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 both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At March 31, 2007, the ratio was approximately 49% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was

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approximately 4.7 times under APS’ bank financing agreements as of March 31, 2007. 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. See further discussion of “cross-default” provisions below.
     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 rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
     All of Pinnacle West’s loan 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 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, the 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, 2007, APS’ common equity ratio, as defined, was approximately 53%.
     Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. 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 plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity and short-term investments. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. We contributed $47 million in 2006. The contribution to our pension plan in 2007 is estimated to be approximately $22 million, and the contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $21 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.

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     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. On December 15, 2006, APS filed a financing application with the ACC requesting an increase in APS’ current short-term and long-term debt authorizations. In the financing application, APS requested an increase to its current short-term debt authorization (7% of APS’capitalization) to 7% of APS’capitalization plus $500 million in order to meet its growing working capital needs. In addition, APS requested an increase to its current long-term debt authorization (approximately $3.2 billion) to approximately $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected future financing needed to fund APS’ capital expenditure and maintenance program and other cash 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.
     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, 2007 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.
     See “Overview” above and Note 4 for discussion of Pinnacle West Marketing & Trading, the Company’s newly-formed marketing and trading subsidiary.
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,

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expenses and related disclosures at the date of the financial statements and during the reporting 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 2006 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2006 Form 10-K for further details about our critical accounting policies.
OTHER ACCOUNTING MATTERS
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance.
     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance.
     See Note 8 for a discussion of FASB Interpretation No. 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial.
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. For the years 2004 through 2006, retail electric revenues comprised approximately 82% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer mix, customer growth, average usage per customer, electricity rates and tariffs, variations in weather from period to period, and amortization of PSA deferrals. Competitive retail sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition. Off-System Sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because the gross margin is credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including demand and prices. Competitive wholesale transactions are made by the marketing and trading group through structured trading opportunities involving matched sales and purchases of commodities.
     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, which are discussed in greater detail in Note 5. The most significant pending retail rate proceedings are APS’ general rate case request and an application for a 1.9% PSA surcharge, or temporary rate

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increase, related to incremental replacement power costs incurred by APS in 2005 in connection with unplanned outages at Palo Verde, which is subject to the ACC’s review of the unplanned outages. These matters have been consolidated procedurally and a decision on them by the ACC is expected in the second quarter of 2007. In addition, the ACC staff is conducting a review of the prudence of approximately $79 million in PSA deferrals related to 2006 unplanned outages at Palo Verde.
     Fuel and Purchased Power Costs Fuel and purchased power costs included on our income statements 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 in our market areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the amortization thereof. See “Power Supply Adjustor” in Note 5 for information regarding the PSA, including PSA deferrals related to Palo Verde unplanned outages and reduced power operations that are the subject of ACC prudence reviews. 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 for the three-month period ended March 31, 2007 was 3.8% compared with the prior-year period. Such growth averaged 4.1% a year for the three years from 2004 through 2006; and we currently expect customer growth to average about 4.0% per year from 2007 to 2009. For the three years 2004 through 2006, APS’ actual retail electricity sales in kilowatt-hours grew at an average rate of 4.2%; adjusted to exclude effects of weather variations, such retail sales growth averaged 4.6% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.2% on average, from 2007 through 2009, before the effects of weather variations. We currently expect our retail sales growth in 2007 to be below average because of potential effects on customer usage from the retail rate increases proposed by APS (see Note 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 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 Market Conditions Our marketing and trading activities focus primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. Our marketing and trading activities include, subject to specified parameters, marketing, hedging and trading in electricity, fuels and emission allowances and credits.

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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, changes in depreciation and amortization rates, and changes in regulatory asset amortization.
     Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessed valuation ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.9% of assessed value for 2006 and 9.2% for 2005. We expect property taxes to increase as new power plants (including the Sundance Plant acquired in 2005) and additions to our 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 are expected to be our capital expenditures, long-term debt maturities, and 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. We cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
     Subsidiaries SunCor’s net income was $61 million in 2006, $56 million in 2005, and $45 million in 2004. See Note 17 for further discussion. We currently expect SunCor’s net income in 2007 will be between $30 million and $35 million. This estimate reflects a slow-down in the western United States residential real estate markets.
     APS Energy Services’ and El Dorado’s historical results are not indicative of future performance.
     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 fixed income securities held by our nuclear

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decommissioning trust fund. The nuclear decommissioning trust fund also has risks 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 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:
    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 activities.
     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, 2007 and 2006 (dollars in millions):

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    Three Months Ended     Three Months Ended  
    March 31, 2007     March 31, 2006  
    Regulated     Marketing     Regulated     Marketing  
    Electricity     and Trading     Electricity     and Trading  
Mark-to-market of net positions at beginning of period
  $ (62 )   $ 77     $ 335     $ 181  
Recognized in earnings:
                               
Change in mark-to-market gains (losses) for future period deliveries
    5       6       (5 )      
Mark-to-market gains realized including ineffectiveness during the period
    (2 )     (4 )     (4 )     (1 )
Deferred as a regulatory liability (asset)
    53             (49 )      
Recognized in OCI:
                               
Change in mark-to-market for future period deliveries – gains (losses) (a)
    51       12       (163 )     (42 )
Mark-to-market (gains) losses realized during the period
    1       (6 )     (10 )     (7 )
Change in valuation techniques
                       
 
                       
Mark-to-market of net positions at end of period
  $ 46     $ 85     $ 104     $ 131  
 
                       
 
(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, 2007 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 2006 Form 10-K for more discussion of our valuation methods.
Regulated Electricity
                                                         
                                            Years     Total fair  
Source of Fair Value   2007     2008     2009     2010     2011     thereafter     value  
Prices actively quoted
  $ 26     $ 22     $ 2     $ 3     $     $     $ 53  
Prices provided by other external sources
    12                                     12  
Prices based on models and other valuation methods
    (3 )     (2 )     (1 )     (4 )     (2 )     (7 )     (19 )
 
                                         
Total by maturity
  $ 35     $ 20     $ 1     $ (1 )   $ (2 )   $ (7 )   $ 46  
 
                                         

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Marketing and Trading
                                                         
                                            Years     Total fair  
Source of Fair Value   2007     2008     2009     2010     2011     thereafter     value  
Prices actively quoted
  $ 15     $     $     $     $     $     $ 15  
Prices provided by other external sources
    37       21                   2       2       62  
Prices based on models and other valuation methods
    (6 )     18       (1 )     (1 )     (1 )     (1 )     8  
 
                                         
Total by maturity
  $ 46     $ 39     $ (1 )   $ (1 )   $ 1     $ 1     $ 85  
 
                                         
     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, 2007 and December 31, 2006 (dollars in millions):
                                 
    March 31, 2007     December 31, 2006  
    Gain (Loss)     Gain (Loss)  
    Price Up     Price     Price Up     Price  
    10%     Down 10%     10%     Down 10%  
Commodity
                               
Mark-to-market changes reported in OCI (a):
                               
Electricity
  $ 40     $ (40 )   $ 38     $ (38 )
Natural gas
    88       (88 )     80       (80 )
 
                       
Total
  $ 128     $ (128 )   $ 118     $ (118 )
 
                       
 
(a)   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 11% of Pinnacle West’s risk management and trading assets as of March 31, 2007. See Note 1, “Derivative Accounting” in Item 8 of our 2006 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

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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.
Deferred Fuel and Purchased Power Costs
     APS settled its 2003 general retail rate case 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. (See “Power Supply Adjustor” in Note 5.)
     Since the inception of the PSA, APS has incurred substantially higher fuel and purchased power costs than those authorized for recovery through APS’ current base rates, primarily due to the use of higher cost resources and higher fuel prices, and has deferred those cost differences in accordance with the PSA. The balance of APS’ PSA accumulated unrecovered deferrals at March 31, 2007 was approximately $118 million. The recovery of PSA deferrals through ACC approved adjustors and surcharges recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses recorded as fuel and purchased power.
     APS recorded PSA deferrals of (a) $45 million related to replacement power costs in 2005 associated with unplanned Palo Verde outages and (b) $79 million related to replacement power costs in 2006 associated with unplanned outages or reduced power operations at Palo Verde. The PSA deferrals associated with these unplanned Palo Verde outages and reduced power operations are the subject of ACC prudence reviews. The ACC staff has completed its prudence review of 2005 unplanned outages and has recommended disallowance of $16 million of the 2005 costs. The recommendation is being considered as part of APS’ general rate case currently pending before the ACC. See “PSA Deferrals Related to Unplanned Palo Verde Outages” in Note 5. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the deferrals related to the unplanned 2005 Palo Verde outages. See “ALJ Recommended Order” in Note 5. Neither the ACC staff recommendation nor the ALJ recommendation changes management’s belief that the expenses in question were prudently incurred and, therefore, are recoverable. The prudence review of 2006 unplanned outages has not yet been completed.
Operating Results – Three-month period ended March 31, 2007 compared with three-month period ended March 31, 2006
     APS’ net income for the three months ended March 31, 2007 was $4 million compared with a net loss $6 million for the comparable prior-year period. The $10 million increase was primarily due to the effects of cooler weather on retail sales; higher retail sales due to customer growth; and lower operations and maintenance expense related to generation. In addition, higher fuel and purchased power costs were partially offset by the deferral of such costs in accordance with the PSA. See “Deferred Fuel and Purchased Power Costs” above.

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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  
Gross margin:
               
Effects of cooler weather on retail sales
  $ 13     $ 8  
Higher retail sales due to customer growth, excluding weather effects
    10       6  
Higher fuel and purchased power costs due to increased prices (see “Deferred Fuel and Purchased Power Costs” above)
    (14 )     (9 )
Increased deferred fuel and purchased power costs
    12       7  
Lower gains on marketing and trading
    (9 )     (5 )
Miscellaneous items, net
    3       3  
 
           
Net increase in gross margin
    15       10  
Operations and maintenance decreases primarily due to:
               
Generation costs, including fewer power plant maintenance outages
    4       2  
Miscellaneous items, net
    3       2  
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates
    (5 )     (3 )
Miscellaneous items, net
    (2 )     (1 )
 
           
Net increase in net income
  $ 15     $ 10  
 
           
Regulated Electricity Revenues
     Regulated electricity revenues were $70 million higher for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:
    a $51 million increase in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see “Deferred Fuel and Purchased Power Costs” above);
 
    an $18 million increase in retail revenues due to cooler weather;
 
    a $13 million increase in retail revenues related to customer growth, excluding weather effects;
 
    a $5 million decrease in Off-System Sales due to lower sales volumes; and
 
    a $7 million decrease due to miscellaneous factors.
Marketing and Trading Revenues
     Marketing and trading revenues were $9 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of a decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices.

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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 2006 Form 10-K, with the exception of our aggregate fuel and purchased power commitments, which increased from approximately $2.5 billion at December 31, 2006 to $2.7 billion at March 31, 2007 as follows (dollars in billions):
                                 
2007   2008-2009   2010-2011   Thereafter   Total
$0.5
  $ 0.5     $ 0.4     $ 1.3     $ 2.7  
     See Note 4 for a list of APS’ payments due on total long-term debt and capitalized lease requirements.
     Upon adoption of FIN 48, APS is now required to include uncertain tax positions in the contractual obligations disclosure. APS has uncertain tax positions of approximately $179 million and expects to pay these in 2007. See Note 8.
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 2006 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, including such deferrals in 2005 and 2006 associated with unplanned Palo Verde outages and reduced power operations that are the subject of ACC prudence reviews;
 
    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;

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    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 value of our nuclear decommissioning trust, pension, and other postretirement benefit plan assets, the amount of required contributions to Pinnacle West’s pension plan and contributions to 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, 2007. 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, 2007. 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, 2007 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 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 2006 Form 10-K, which could materially affect the business, financial condition or future results of APS and Pinnacle West. The risks described in the 2006 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 for a discussion of regulatory developments.
Environmental Matters
     See “Environmental Matters – Superfund” in Note 12 for a discussion of a Superfund site.
     Federal Implementation Plan (“FIP”)
     In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and the Four Corners Power Plant. On July 26, 2006, the Sierra Club sued the EPA in an attempt to force the EPA to issue a final FIP to limit emissions at the Four Corners Power Plant. On September 12, 2006, the EPA proposed a revised FIP to establish air quality standards at Four Corners and the Navajo Generating Station. On September 18, 2006, APS filed a motion to intervene in the Sierra Club’s lawsuit against the EPA, in order to assure that its interests are protected. On November 22, 2006, the court granted APS’ motion to intervene in the lawsuit. In December 2006, the court issued a consent decree signed by the Sierra Club and the EPA; the consent decree requires EPA to take “final action” on the proposed FIP by April 30, 2007. On April 30, 2007, the EPA issued the final FIP for Four Corners. The FIP essentially federalizes the requirements contained in the New Mexico State Implementation Plan, which Four Corners has historically followed. The FIP also includes a requirement to control fugitive dust within 18 months after the FIP becomes effective. (Fugitive dust is dust that is blown within the vicinity of the plant as a result of human activity, the wind, or both.) We do not believe the Four Corners FIP will have a material impact on our financial position, results of operations, cash flows or liquidity. The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently predict the effect of this proposed FIP on the Company’s financial position, results of operations, cash flows or liquidity, or whether the proposed FIP will be adopted in its current form.

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     Regional Haze Rules
     On April 22, 1999, the EPA announced final regional haze rules. These regulations require states to submit state implementation plans (SIPs) by December 2007 to demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class I Areas,” including several on the Colorado Plateau. The SIP is required to consider and potentially apply “best available retrofit technology” (BART) for certain older major stationary sources. The rules allow nine western states and tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.
     On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional haze rules by providing guidelines, known as the BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use. The EPA also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court remand of that rule.
     The Arizona Department of Environmental Quality (ADEQ) is currently undertaking a rulemaking process to amend its SIP to reconcile it with the Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. As part of the rulemaking process, the ADEQ will require certain sources in the state to conduct BART analyses, potentially including Cholla and other APS plants. The ADEQ’s Regional Haze SIPs are due to EPA Region 9 in December 2007. In addition, we anticipate that EPA Region 9 may require Four Corners to conduct a BART analysis. The Company cannot currently predict the outcome of these proceedings.
     Greenhouse Gas Accord
     On February 26, 2007 five western states (Arizona, California, New Mexico, Oregon and Washington) entered into an accord to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. The agreement requires the states to set emission goals within six months and determine a specific plan to meet such goals within eighteen months. While we continue to monitor the impact of this accord, we cannot predict its impact on our operations at this time.
     Hazardous Air Pollutants Rule
     ADEQ promulgated a Hazardous Air Pollutants (HAPs) rule that became effective on January 1, 2007. The HAPs rule requires certain sources of HAPs to evaluate and potentially apply pollution control technologies to limit HAPs emissions, or demonstrate through a risk management analysis that controls are not warranted. The rule is being challenged for its validity and currently does not apply in the counties in which APS has power plants. The APS plants potentially subject to HAPs regulation are the Saguaro Power Plant, located in Pinal County, and the Ocotillo and West Phoenix Power Plants, located in Maricopa County. State law requires these counties to adopt their own versions of the rule, and Maricopa County already is in the process of doing so. APS is monitoring the HAPs rule, its impact in the relevant counties and its validity. APS does not expect this matter to have a material adverse effect on its financial statements, results of operations, cash flows or liquidity.

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Item 6. EXHIBITS
     (a) Exhibits
         
Exhibit No.   Registrant(s)   Description
10.1
  Pinnacle West
APS
  Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of May 1, 2007
 
       
10.2
  Pinnacle West
APS
  Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of May 1, 2007
 
       
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

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Exhibit No.   Registrant(s)   Description
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
     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 Exhibit a   Filed
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, 2007  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, 2007  By:   /s/ Donald E. Brandt    
    Donald E. Brandt    
    President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)   
 

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