8-K 1 p13534e8vk.htm FORM 8-K e8vk
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): November 25, 2008
         
    Exact Name of Registrant as Specified in    
    Charter; State of Incorporation;   IRS Employer
Commission File Number   Address and Telephone Number   Identification Number
 
1-8962
  Pinnacle West Capital Corporation   86-0512431
 
  (an Arizona corporation)    
 
  400 North Fifth Street, P.O. Box 53999    
 
  Phoenix, AZ 85072-3999    
 
  (602) 250-1000    
 
       
1-4473
  Arizona Public Service Company   86-0011170
 
  (an Arizona corporation)    
 
  400 North Fifth Street, P.O. Box 53999    
 
  Phoenix, AZ 85072-3999    
 
  (602) 250-1000    
     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
o   Written communications pursuant to Rule 425 under the Securities Act (17CFR 230.425)
 
o   Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
 
o   Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
 
o   Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
     This combined Form 8-K 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 8-K 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.
 
 

 


 

ITEM 8.01. OTHER EVENTS
          This Current Report on Form 8-K is limited to the disclosure of the reclassification of financial statements of Pinnacle West Capital Corporation (the “Company” or “Pinnacle West”) and of Arizona Public Service Company (“APS”) to reflect certain reclassifications of marketing and trading assets and liabilities to a net basis of reporting and to reflect reclassifications of certain activities of SunCor Development Company (“SunCor”) to discontinued operations.
          This report reflects the impacts of the reclassifications on portions of the following disclosures in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007 (“2007 Form 10-K”):
    Item 1. Business;
 
    Item 6. Selected Financial Data;
 
    Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations;
 
    Item 8. Financial Statements and Supplementary Data; and
 
    Item 15. Exhibits and Financial Statement Schedules.
NO ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE OTHER DISCLOSURES EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE RECLASSIFICATIONS DESCRIBED BELOW.
          As previously disclosed in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008 (“March 2008 Form 10-Q”), we adopted Financial Accounting Standards Board (“FASB”) Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1) on January 1, 2008. In accordance with this guidance, we elected to offset fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting agreement. FIN 39-1 requires retrospective application for all prior periods presented. Our March 2008 Form 10-Q, our Form 10-Q for the fiscal quarter ended June 30, 2008 (“June 2008 Form 10-Q”), and our Form 10-Q for the fiscal quarter ended September 30, 2008 (“September 2008 Form 10-Q”), previously filed with the Securities and Exchange Commission, reflect such reclassifications.
          Also, as previously disclosed in our March 2008 Form 10-Q, June 2008 Form 10-Q and September 2008 Form 10-Q, certain activities related to SunCor were required to be reported as discontinued operations in accordance with Statement of Financial Accounting Standards (“SFAS”) 144. Among other guidance, SFAS 144 prescribes accounting for discontinued operations and defines certain activities as discontinued operations. The March 2008 Form 10-Q, June 2008 Form 10-Q and September 2008 Form 10-Q reflect reclassifications related to certain SunCor discontinued activities for 2007.
           This Current Report on Form 8-K provides updated information to substantially conform the 2007 Form 10-K to the presentation reported in our March 2008 Form 10-Q, June 2008 Form 10-Q and September 2008 Form 10-Q.

 


 


 

GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
AFUDC – Allowance for Funds Used During Construction
ALJ – Administrative Law Judge
ANPP – Arizona Nuclear Power Project, also known as Palo Verde
APS – Arizona Public Service Company, a subsidiary of the Company
APSES – APS Energy Services Company, Inc., a subsidiary of the Company
Base Fuel Rate – the portion of APS’ retail base rates attributable to fuel and purchased power costs
Cholla – Cholla Power Plant
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
FIP – Federal Implementation Plan
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
kW – kilowatt, one thousand watts
kWh – kilowatt-hour, one thousand watts per hour
Moody’s – Moody’s Investors Service
MW – megawatt, one million watts
MWh – megawatt-hour, one million watts per hour
NAC – collectively, NAC Holding Inc. and NAC International Inc., subsidiaries of El Dorado that were sold in November 2004
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
Note – a Note to Pinnacle West’s Consolidated Financial Statements in Item 8 of this report

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NPC – Nevada Power Company
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 (PWEC) – Pinnacle West Energy Corporation, a subsidiary of the Company, dissolved as of August 31, 2006
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 approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate
PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
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 – 420 megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona
Superfund – Comprehensive Environmental Response, Compensation and Liability Act

2005 Deferrals – PSA deferrals related to 2005 replacement power costs associated with Palo Verde outages
2006 Deferrals – PSA deferrals related to 2006 replacement power costs associated with outages or reduced power operations at Palo Verde
VIE – variable-interest entity
West Phoenix – West Phoenix Power Plant

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BUSINESS
OVERVIEW
General
     Pinnacle West was incorporated in 1985 under the laws of the State of Arizona and owns all of the outstanding equity securities of APS, its major subsidiary. APS is a vertically-integrated electric utility that provides either retail or 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.
     Pinnacle West’s other principal subsidiary is SunCor, which is engaged in real estate development activities in the western United States. See “Business of SunCor Development Company” in this Item 1. Pinnacle West’s other first-tier subsidiaries, APSES, El Dorado and Pinnacle West Marketing & Trading are discussed in “Business of Other Subsidiaries” in this Item 1.
     Pinnacle West Energy, which owned and operated unregulated generating plants, transferred the PWEC Dedicated Assets to APS on July 29, 2005 and sold its 75% ownership interest in Silverhawk to NPC on January 10, 2006. As a result, Pinnacle West Energy no longer owned any generating plants and was dissolved as of August 31, 2006.
Business Segments
     Pinnacle West has two principal business segments (determined by products, services and the regulatory environment):
    the regulated electricity segment (accounting for 83% of operating revenues in 2007), 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
 
    the real estate segment (accounting for 6% of operating revenues in 2007), which consists of SunCor’s real estate development and investment activities.
     See Note 17 for financial information about the business segments.
APS ACC Proceedings
     The key issue affecting Pinnacle West’s and APS’ financial outlook is adequate and timely retail rate treatment by the ACC. Note 3 discusses the results of APS’ most recent retail rate case as well as other rate matters.
Employees
     At December 31, 2007, Pinnacle West employed approximately 7,600 people, including the employees of its subsidiaries. Of these employees, approximately 6,800 were employees of APS, including employees at jointly-owned generating facilities (approximately 3,000 employees) for which APS serves as the generating facility manager. Approximately 800 people were employed by

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Pinnacle West and its other subsidiaries. Pinnacle West’s principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).
Available Information
     Pinnacle West makes available free of charge on or through its internet site, (www.pinnaclewest.com) the following filings as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC: its Annual Report on Form 10-K, its Quarterly Reports on Form 10-Q, its Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934.
     Pinnacle West also has a Corporate Governance webpage. You can access Pinnacle West’s Corporate Governance webpage through its internet site, www.pinnaclewest.com, by clicking on the “About Us” link to the heading “Corporate Commitments.” Pinnacle West posts the following on its Corporate Governance webpage:
    Corporate Governance Guidelines;
 
    Board Committee Summary;
 
    Charters for Pinnacle West’s Audit Committee, Corporate Governance Committee, Finance, Nuclear and Operating Committee and Human Resources Committee;
 
    Code of Ethics for Financial Professionals;
 
    Ethics Policy and Standards of Business Practices;
 
    Director Independence Standards;
 
    Executive Officer Stock Ownership Guidelines; and
 
    Restricted Stock Retention Policy.
 
     Pinnacle West will post any amendments to the Code of Ethics and Ethics Policy and Standards of Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its internet site. The information on Pinnacle West’s internet site is not incorporated by reference into this report.
     You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 9068, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-3252).
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 this report, these factors include, but are not limited to:

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    state and federal regulatory and legislative decisions and actions, particularly those affecting our rates and our recovery of fuel and purchased power costs;
 
    the outcome of regulatory, legislative and judicial proceedings, both current and future, relating to the restructuring of the electric industry and environmental matters (including those related to climate change);
 
    the ongoing restructuring of the electric industry, including decisions impacting wholesale competition and the introduction of retail electric competition in Arizona;
 
    market prices for electricity and natural gas;
 
    volatile market liquidity, 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);
 
    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 and Pacific Northwest energy situations, volatile fuel and purchased power costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;
 
    the cost of debt and equity capital and access to capital markets;
 
    current credit ratings remaining in effect for any given period of time;
 
    our ability to compete successfully outside traditional regulated markets (including the wholesale market);
 
    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.
REGULATION AND COMPETITION
Retail
     The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must also approve any transfer or encumbrance of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates.

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     APS is subject to varying degrees of competition from other investor-owned utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet their own energy requirements.
     In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. As a result, as of January 1, 2001, all of APS’ retail customers were eligible to choose alternate energy suppliers. However, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. In 2000, an Arizona Superior Court found that the rules were in part unconstitutional and in other respects unlawful, the latter finding being primarily on procedural grounds, and invalidated all ACC orders authorizing competitive electric services providers to operate in Arizona. In 2004, the Arizona Court of Appeals invalidated some, but not all of the rules and upheld the invalidation of the orders authorizing competitive electric service providers. In 2005, the Arizona Supreme Court declined to review the Court of Appeals decision. To date, the ACC has taken no action on either the rules or the prior orders authorizing competitive electric service providers in response to the final Court of Appeals decision. As a result, at present only limited electric retail competition exists in Arizona and only with certain entities not regulated by the ACC. However, the ACC has scheduled a hearing during the first quarter of 2008 to consider the new application of a competitive electric service provider for authority to provide competitive electric services. Certain intervenors in that proceeding have requested the ACC to dismiss the application because of, among other reasons, the legal uncertainties associated with the rules, as described above. The ACC has taken this motion to dismiss under advisement. APS cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
Wholesale
     General
     The FERC regulates rates for wholesale power sales and transmission services. See “Rate Requests for Transmission and Ancillary Services” in Note 3 for information regarding APS’ pending rate case at the FERC. During 2007, approximately 4.4% of APS’ electric operating revenues resulted from such sales and services. APS’ wholesale activity primarily consists of managing fuel and purchased power risks in connection with the costs of serving retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’ Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS markets, hedges and trades principally in electricity and fuels.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
General
     APS was incorporated in 1920 under the laws of the state of Arizona and currently has approximately 1.1 million customers. APS does not distribute any products. During 2007, no single purchaser or user of energy accounted for more than 5.8% of electric revenues. See “Overview” and “Regulation and Competition” above for additional background information about APS.

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     At December 31, 2007, APS employed approximately 6,800 people, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. APS’ principal executive offices are located at 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-1000).
Portfolio Resources
     APS’ sources of energy during 2007 were: coal – 36.8%; purchased power – 23.3%; nuclear – 21.5%; and gas – 18.4%. In accordance with GAAP, a substantial portion of APS’ purchased power expense is netted against wholesale sales on the Consolidated Statements of Income. See Note 18. The disclosure below provides a more detailed description of each of APS’ current sources of energy.
     Generation Facilities
     APS’ portfolio of owned or leased generating capacity is provided in the table below:
         
    Capacity (kW)  
Coal:
       
Units 1, 2 and 3 at Four Corners
    560,000  
15% owned Units 4 and 5 at Four Corners
    225,000  
Units 1, 2 and 3 at Cholla
    641,000  
14% owned Units 1, 2 and 3 at the Navajo Generating Station
     315,000  
 
     
 
       
Subtotal
    1,741,000  
 
     
 
       
Gas or Oil:
       
Two steam units at Ocotillo and two steam units at Saguaro
    430,000  
Twenty-two combustion turbine units
    992,000  
Seven combined cycle units
    1,862,000  
 
     
 
       
Subtotal
    3,284,000  
 
     
 
       
Nuclear:
       
29.1% owned or leased Units 1, 2 and 3 at Palo Verde
    1,126,752 1
 
     
 
       
Solar
           5,817  
 
     
 
       
Total
    6,157,569  
 
     
 
1   As of January 26, 2008, nuclear capacity increased to 1,147,122 kW, reflecting completion of the steam generator replacement program.
     Coal Fueled Generating Facilities
     Four Corners – Four Corners is a coal-fired power plant located in the northwestern corner of New Mexico. APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units 4 and 5. APS purchases all of Four Corners’ coal requirements from a supplier

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with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016, with options on APS’ part to extend the contract for five to fifteen additional years. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” below for additional information.
     Cholla – Cholla is a coal-fired power plant located in northeastern Arizona. APS operates the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4 and APS operates that unit for PacifiCorp. Cholla’s common facilities are jointly owned by APS and PacifiCorp. APS purchases most of Cholla’s coal requirements from coal suppliers that mine all of the coal under long-term leases of coal reserves with the Navajo Nation, the federal government and private landholders. There are currently two coal contracts in place with two separate suppliers for Cholla. One supplier is ramping down its supply to the plant, which will be complete in 2009, and the other is ramping up its supply to the plant to provide Cholla’s full coal requirement by 2010. This agreement runs through 2024. Additionally, APS may purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options and to supplement coal required for increased operating capacity. APS believes that the current fuel contracts and competitive fuel supply options ensure the continued operation of Cholla for its useful life. In addition, APS has a long-term coal transportation contract.
     Navajo Generating Station – The Navajo Generating Station is a coal-fired power plant located in northern Arizona. Salt River Project operates the plant and APS owns a 14% interest in Navajo Units 1, 2 and 3. The Navajo Generating Station’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under contract with its coal supplier through 2011, with options to extend through 2019. The Navajo Generating Station plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” below for additional information.
     See “Legal Proceedings” in Item 3 for information about a lawsuit relating to royalties for coal paid by the participants at the Navajo Generating Station.
     See Note 11 for information regarding APS’ coal mine reclamation obligations.
     Natural Gas Fueled Generating Facilities
     APS has seven natural gas power plants located throughout Arizona, consisting of Redhawk, located near the Palo Verde Nuclear Generating Station; Ocotillo, located in Tempe; Sundance, located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson; Douglas, located in the town of Douglas; and Yucca, located near Yuma. APS owns and operates each plant with the exception of one combustion turbine unit and one steam unit at Yucca that are operated by APS and owned by the Imperial Irrigation District.
     Nuclear Generating Facility
     Palo Verde Nuclear Generating Station – Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and about 17% of Unit 2. In addition, APS leases about 12.1% of Unit 2, resulting in a 29.1%

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combined interest in that Unit. See “Palo Verde Leases” below for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.
     Palo Verde Fuel Cycle – The fuel cycle for Palo Verde is comprised of the following stages:
    mining and milling of uranium ore to produce uranium concentrates;
 
    conversion of uranium concentrates to uranium hexafluoride;
 
    enrichment of uranium hexafluoride;
 
    fabrication of fuel assemblies;
 
    utilization of fuel assemblies in reactors; and
 
    storage and disposal of spent nuclear fuel.
     The Palo Verde participants are continually identifying their future resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2008 and for approximately 50% of uranium concentrates and conversion services in 2009. The participants have also contracted for all of Palo Verde’s enrichment services through 2013 and all of Palo Verde’s fuel assembly fabrication services until at least 2015.
     Spent Nuclear Fuel and Waste Disposal – See “Palo Verde Nuclear Generating Station” in Note 11 for a discussion of spent nuclear fuel and waste disposal.
     Palo Verde Leases – In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases and to purchase the property for fair market value at the end of the lease terms. See Notes 9 and 20 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.
     Regulatory Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize APS, as operating agent for Palo Verde, to operate the three Palo Verde units at full power.
     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. 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 (“Column 4”), which has resulted in an enhanced NRC inspection regime. Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS’ management has been conducting site-wide assessments of equipment and operations.
     Preliminary work in support of the NRC’s enhanced inspection regime took place throughout the summer of 2007. On June 21, 2007, the NRC issued an initial confirmatory action letter

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confirming APS’ commitments regarding specific actions APS will take to improve Palo Verde’s performance. From October 1, 2007 through November 2, 2007, a team of NRC inspectors performed on-site in-depth inspections of Palo Verde’s equipment and operations. The NRC’s inspection results were presented at a public meeting on December 19, 2007, and documented in an NRC letter to APS dated February 1, 2008 (the “Inspection Report”). The Inspection Report indicated that the facility is being operated safely, but also identified certain performance deficiencies. On December 31, 2007, APS submitted its improvement plan to the NRC, which addresses issues identified by APS’ management during its site-wide assessments of equipment and operations that occurred during 2007. The NRC reviewed the adequacy of this improvement plan and issued a revised confirmatory action letter on February 15, 2008 that outlines the actions APS must take in order for the NRC to return the Palo Verde site to the NRC’s routine inspection and assessment process. This revised confirmatory action letter was anticipated as part of the NRC’s inspection procedure and a substantial majority of the actions required therein were contained in APS’ improvement plan. In March 2008, APS intends to submit to the NRC a revision to its improvement plan to address issues raised by the NRC in its Inspection Report. The NRC will continue to provide increased oversight at Palo Verde until the facility demonstrates sustained performance improvement. APS will continue cooperating fully with the NRC throughout this process.
     Nuclear Decommissioning Costs The NRC rules on financial assurance requirements for the decommissioning of nuclear power plants provide that a licensee may use a trust as the exclusive financial assurance mechanism if the licensee recovers estimated total decommissioning costs through cost-of-service rates or through a “non-bypassable charge.” The “non-bypassable systems benefits” charge is the charge that the ACC has approved for APS’ recovery of certain types of costs, including costs for low income programs, demand side management, consumer education, environmental, renewables, etc. “Non-bypassable” means that if a customer chooses to take energy from an “energy service provider” other than APS, the customer will still have to pay this charge as part of the customer’s APS electric bill.
     Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on an external sinking fund mechanism are not met. APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’ ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge, which allows APS to maintain its external sinking fund mechanism. See Note 12 for additional information about APS’ nuclear decommissioning costs.
     Palo Verde Liability and Insurance Matters – See “Palo Verde Nuclear Generating Station” in Note 11 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.
     Alternative Generation Sources
     In connection with its ongoing resource planning efforts, APS continues to focus on increasing the percentage of its energy that is produced by renewable resources. On November 1, 2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (the “Renewable Energy Standard”). Under the Renewable Energy Standard, covered utilities like APS must supply an increasing percentage of their retail electric energy sales from renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement

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increases from 1.5% in 2007 to 15% in 2025. In addition, an increasing percentage of that requirement must be supplied from distributed resources (generally speaking, small-scale renewable technologies that are located on customers’ properties) to increase system reliability. The distributed resource requirement increases from 5% of the overall renewable energy requirement in 2007 to 30% in 2012 and subsequent years. APS currently has a diverse portfolio of renewable resources including wind from New Mexico, geothermal from California and Utah, and solar and biomass in Arizona, which collectively will generate over 120 MW of renewable energy for our customers.
     On February 8, 2008, APS entered into a Renewable Energy Purchase and Sale Agreement under which APS agreed to purchase the energy and related renewable energy credits from a solar power plant for a period of thirty years after the plant begins commercial operation. The plant, which will have a nameplate rating of 280 MW and a projected annual output of 900,000 MWh, will be located near Gila Bend, Arizona, about 70 miles southwest of Phoenix, Arizona. The agreement is subject to various conditions, including ACC approval. If these conditions are met, commercial operation is expected during 2011.
     APS continues to actively consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the Renewable Energy Standard and to meet the needs of its customer base.
     Purchased Power Agreements
     In addition to its own available generating capacity, APS purchases electricity under various arrangements. APS’ purchased power capacity under long-term contracts, as of December 31, 2007, is summarized in the table below, and does not include the recently-executed solar agreement described under “Alternative Generation Sources.” APS also purchases power through short-term markets to supplement its long-term resources and hedge its energy requirements.
             
Purchased Power Agreement   Dates Available   Capacity (MW)
Purchase Agreement (a)
  Year-round through June 15, 2010     234  
Exchange Agreement (b)
  May 15 to September 15 annually through 2020     480  
Tolling Agreement
  June 2007 through May 2017     510  
Tolling Agreement
  June 2010 through October 2019     560  
Day-Ahead Call Option Agreement
  June 2007 through September 2015 (summer seasons)     500  
Day-Ahead Call Option Agreement
  June 2007 through summer 2016     150  
Wind Agreement
  December 2006 through December 2026     90  
Geothermal Agreement
  January 2006 through 2029     10  
Landfill Gas Agreement
  Deliveries expected to commence in 2008; expires 2028     3  
Biomass Agreement
  Deliveries expected to commence in 2008; expires 2022     14  
 
(a)   The amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually. Effective June 16, 2007, the seller, Salt River

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    Project, reduced the capacity available to APS by 150 MW. Additionally, Salt River Project has elected to cancel this contract effective June 15, 2010.
 
(b)   This is a seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and APS returns electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2007, APS received 571,342 MWh of energy under the capacity exchange. Additionally, under a supplemental energy sales agreement, APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2007, PacifiCorp received offers of 1,093,175 MWh and purchased 174,340 MWh.
     APS continually assesses its need for additional capacity resources to assure system reliability. APS remains committed to seeking proposals from the competitive wholesale market for filling its future resource needs, including renewable resource capacity.
     Reserve Margin
     APS’ 2007 peak one-hour demand on its electric system was recorded on August 13, 2007 at 7,545,100 kW, compared with the 2006 peak of 7,652,000 kW recorded on July 21, 2006. Taking into account additional capacity then available to APS under long-term purchased power contracts as well as APS generating capacity, APS had capacity of 6,783,000 kW to meet system demand on August 13, 2007, for an installed reserve margin of negative 11.3%. The power actually available to APS from its resources fluctuates from time to time due in part to planned and unplanned plant and transmission outages and technical problems. The available capacity from sources actually operable at the time of the 2007 peak amounted to 5,839,000 kW, for a margin of a negative 33.5%. Firm purchases totaling 3,484,000 kW, including short-term seasonal purchases and unit-contingent purchases, were in place at the time of the peak, ensuring the ability to meet the load requirement with an actual reserve margin of 10.1%.
Transmission and Distribution Facilities
     APS’ transmission facilities consist of approximately 5,759 pole miles of overhead lines and approximately 45 miles of underground lines, 5,535 miles of which are located in Arizona. APS’ distribution facilities consist of approximately 12,471 miles of overhead lines and approximately 16,210 miles of underground primary cable, all of which are located in Arizona. APS shares ownership of some of its transmission facilities with other companies. The following table shows APS’ jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2007:

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    Percent Owned
    (Weighted Average)
Harquahala
    80.0 %
Palo Verde – Estrella 500KV System
    55.5 %
ANPP 500KV System
    35.8 %
Navajo Southern System
    31.4 %
Four Corners Switchyards
    27.5 %
Palo Verde – Yuma 500KV System
    23.9 %
Phoenix – Mead System
    17.1 %
Plant and Transmission Line Leases and Easements on Indian Lands
     The Navajo Generating Station and Four Corners are located on land held under leases from the Navajo Nation and also under easements from the federal government. The easement and lease for the Navajo Generating Station expire in 2019 and the easement and lease for Four Corners expire in 2016. Each of the leases contains an option to extend for an additional 25-year period from the end of the existing lease term, for a rental amount tied to the original rent payment adjusted based on an index. The easements do not contain an express renewal option and it is unclear what conditions to renewal or extension of the easements may be imposed. The ultimate cost of renewal of the Navajo Generating Station and Four Corners leases and easements is uncertain. As noted above under “Portfolio Resources — Coal Fueled Generating Facilities,” the coal contracted for use in these plants is also located on Indian reservations.
     Certain portions of the transmission lines that carry power from several of our power plants are located on Indian lands pursuant to easements or other rights-of-way that are effective for specified periods. Some of these rights-of-way have expired and our renewal applications have not yet been acted upon by the appropriate Indian tribes. Other rights expire at various times in the future and will have to be acted on for renewal by the applicable tribe at that time. The majority of our transmission lines residing on Indian lands are on the Navajo Nation. The Four Corners and Navajo Generating Station plant leases provide Navajo Nation consent to certain of the rights-of-way for transmission lines related to those plants at a specified rental rate for the original term of the rights-of-way and for a like payment in any renewal period. In addition, a 1985 amendment to the leases provides a formula for calculating payments for certain new and renewal rights-of-way. However, some of our rights-of-way are not covered by the leases, or are granted by other Indian tribes. In recent negotiations with other utilities or companies for renewal of similar rights-of-way, certain of the affected Indian tribes have required payments substantially in excess of amounts that we have paid in the past for such rights-of-way or that are typical for similar permits across non-Indian lands; however, we are unaware of the underlying agreements and/or specific circumstances surrounding these renewals. The ultimate cost of renewal of the rights-of-way for our transmission lines is uncertain. We are monitoring these rights-of-way and easement issues and are currently unable to predict the outcome of this matter.
Construction Program
     During the years 2005 through 2007, APS incurred approximately $2.4 billion in capital expenditures. APS’ capital expenditures for the years 2008 through 2010 are expected to be primarily for expanding transmission and distribution capabilities to meet growing customer needs,

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for upgrading existing utility property and for environmental purposes. APS’ capital expenditures were approximately $900 million in 2007. APS’ capital expenditures, including expenditures for environmental control facilities, for the years 2008 through 2010, have been estimated as follows (dollars in millions):
                         
    Estimate  
    2008     2009     2010  
Major facilities:
                       
Distribution
  $ 410     $ 440     $ 430  
Generation
    380       390       380  
Transmission
    220       320       290  
Other
    50       40       50  
 
                 
Total
  $ 1,060     $ 1,190     $ 1,150  
 
                 
     The above amounts do not include any impacts from the recent changes in the line extension policy (see Note 3). In addition, the amounts exclude capitalized interest costs and include capitalized property taxes. Nuclear fuel expenditures of approximately $90 million to $120 million per year are also included. As part of our planning and cost control process, APS conducts a continuing review of its construction program.
     See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 for additional information about APS’ construction program.
Environmental Matters
     EPA Environmental Regulation
     Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These regulations required 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. SIPs are required to consider and potentially apply “best available retrofit technology” (BART) for certain older major stationary sources. The rules allow nine western states and Indian 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.
     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. ADEQ’s Regional Haze SIPs were due to EPA Region 9 in December 2007, but are actually expected to be submitted during 2008. As part of the rulemaking process, ADEQ is requiring certain sources in the state to conduct BART analyses. Cholla and West Phoenix received letters from ADEQ asserting that the plants are potentially subject to BART and requesting that we either perform a BART analysis on each plant or provide information demonstrating that we are not subject to BART. We

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recently completed a BART analysis for Cholla and submitted our BART recommendations to ADEQ on February 4, 2008. ADEQ will now review our submission and determine what constitutes BART for Cholla. Our recommendations include the installation of certain pollution control equipment that we believe constitutes BART. Once we receive ADEQ’s final determination, we will have five years to complete the installation of the equipment and to achieve the emission limits established by ADEQ. However, in order to coordinate with the plant’s other scheduled activities, we are currently implementing our recommended plan for Cholla on a voluntary basis. Costs related to the implementation of our recommended plan are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7).
     Because we believed that ADEQ’s baseline modeling for West Phoenix may have contained some errors, we re-performed the baseline modeling using correct input and have determined that West Phoenix is not subject to BART. We submitted these findings for West Phoenix to ADEQ, and ADEQ has verbally informed us that West Phoenix is not subject to BART.
     In addition, EPA Region 9 requested us to perform a BART analysis for Four Corners. We recently completed the analysis and submitted it to the EPA on January 30, 2008. The EPA will now review our submission and determine what constitutes BART for Four Corners. Our recommendations include the installation of certain pollution control equipment that we believe constitutes BART. Once we receive the EPA’s final determination, we will have five years to complete the installation of the equipment and to achieve the emission limits established by EPA Region 9. Until the EPA makes a final determination on this matter, we cannot accurately estimate the expenditures that may be required. As a result, our current environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7) do not include amounts for Four Corners BART expenditures.
     While we continue to monitor this matter, at the present time we cannot predict whether the agencies will agree with our BART recommendations or, if the agencies disagree with our recommendations, the nature of the BART controls the agencies may ultimately mandate and the resulting financial or operational impact.
     Mercury On March 15, 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to control mercury emissions from coal-fired power plants. This rule establishes performance standards limiting mercury emissions from coal-fired power plants and establishes a two phased market-based emissions trading program. Under the trading program, the EPA has assigned each state a mercury emissions “budget” and each state must submit to the EPA a plan detailing how it will meet its “budget.” In the first phase of the program, beginning in 2010, mercury emissions from all coal-fired power plants in the country will be reduced from a total of 48 tons per year to 38 tons. In 2018, those emissions will be further reduced to 15 tons.
     In November 2006, ADEQ submitted a SIP to the EPA to implement the CAMR. ADEQ’s SIP generally incorporates the EPA’s model cap-and-trade program, but it includes additional requirements, including the requirement to meet a 90% mercury removal control level or 0.0087 lbs/GWh, whichever is greater, the requirement to obtain mercury allowances at a 2:1 ratio for any emissions that fall below the specified control level, and the requirement, beginning in 2013, to consider clean coal technologies as part of permitting any new generation.

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     On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR and the EPA rule that allowed for the creation of the CAMR. While we continue to monitor this matter, we cannot predict the timing of the court’s issuance of a mandate to vacate the rules, the response of ADEQ or the scope, timing or impact of any alternate rules that may be proposed to address mercury emissions.
     We have installed, and may continue to install, certain of the equipment necessary to meet these mercury standards. However, due to the recent U.S. Court of Appeals decision, we will monitor the type and timing of any necessary equipment installation. The estimated costs expected to be incurred over the next three years for such equipment are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7).
     Federal Implementation Plan In September 1999, the EPA proposed FIPs to set air quality standards at certain power plants, including Four Corners and the Navajo Generating Station. On September 12, 2006, the EPA proposed revised FIPs to establish air quality standards at both of these plants.
     Four Corners FIP
     On April 30, 2007, the EPA adopted a source specific FIP to set air quality standards at 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 maintain and enhance dust suppression methods. On July 2, 2007, APS filed a petition for review in the United States District Court of Appeals for the Tenth Circuit seeking revisions to the FIP to clarify certain requirements and allow operational flexibility. The Sierra Club has intervened in this action. On July 6, 2007, the Sierra Club and other parties filed a petition for review with the same court challenging the FIP’s compliance with the Clean Air Act and we have intervened in their action. In our lawsuit, we challenge two key provisions of the FIP: a 20% opacity limit on certain fugitive dust emissions, which the EPA filed a motion to remand and vacate in early December 2007, and a 20% stack opacity limit on Units 4 and 5. Briefing in this case is now complete, and the court is next expected to determine whether to hold oral arguments on the matter, as requested by the EPA. Although we cannot predict the outcome or the timing of these matters, we do not believe that they will have a material adverse impact on our financial position, results of operations or cash flows.
     Navajo Generating Station FIP
     The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently predict the effect of this proposed FIP on its financial position, results of operations or cash flows, or whether the proposed FIP will be adopted in its current form.
     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

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OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.
     Manufactured Gas Plant Sites APS is currently investigating properties, which it now owns or which were previously owned by it or its corporate predecessors, that were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.
     Navajo Nation Environmental Issues
     Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. See “Portfolio Resources – Coal Fueled Generating Facilities” above for additional information regarding these plants.
     In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Generating Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Generating Station. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement.
     In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo Generating Station participants each filed a petition with the Navajo Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.
     On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Generating Station, and the Navajo Nation executed a Voluntary Compliance Agreement (“VCA”) to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. On March 21, 2006, the EPA determined that the Navajo Nation was eligible for “treatment as a state” for the purpose of entering into a supplemental delegation agreement with the EPA to administer the Clean Air Act Title V, Part 71 federal permit program over Four Corners and the Navajo Generating Station. The EPA entered into the supplemental delegation agreement with the Navajo Nation on the same day. Because the EPA’s approval was consistent with the requirements of the VCA, APS sought dismissal of the pending litigation in the Navajo Nation Supreme Court, as well as the pending litigation in the Navajo Nation District Court to the extent the claims relate to the Clean Air Act, and the Courts have dismissed the claims accordingly. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

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Climate Change
     In 2007, six western states (Arizona, California, New Mexico, Oregon, Utah and Washington) and two Canadian provinces (British Columbia and Manitoba) entered into an accord, the Western Climate Initiative (the “Initiative”), to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. In August 2007, the Initiative participants set a goal of reducing greenhouse gas emissions 15% below 2005 levels by 2020. By August 2008, the Initiative participants intend to develop a plan for implementation of this goal. Any such implementation would require independent action by each individual state’s or province’s legislature or Governor to adopt a version of the plan. While we continue to monitor the impact of the Initiative, at the present time we cannot predict what form it will ultimately take, whether it will be implemented or, if it is implemented, what impact it will have on our operations.
     We are currently developing a Climate Management Report to comply with an ACC order in which the ACC directed APS to undertake a climate management plan, carbon emission reduction study and commitment and action plan with public input and ACC review. We expect to complete the report in 2008.
     In January 2008, APS joined the Climate Registry as a Founding Reporter. Founding Reporters are companies that voluntarily join the non-profit organization before May 2008 to measure and report greenhouse gas emissions in a common, accurate and transparent manner consistent across industry sectors and borders. Pinnacle West also makes available on its website (www.pinnaclewest.com) its annual Corporate Responsibility Report, which provides information related to the Company, its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.
Water Supply
     Assured supplies of water are important for APS’ generating plants. At the present time, APS has adequate water to meet its needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions.
     Both groundwater and surface water in areas important to APS’ operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.
     A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County, Arizona, Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’ rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’ other power plants are also

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located within the geographic area subject to the summons. APS’ claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’ water rights claims has been set in this matter.
     APS has also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’ claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’ water rights claims has been set in this matter.
     Although the above matters remain subject to further evaluation, neither APS nor Pinnacle West expects that the described litigation will have a material adverse impact on its financial position, results of operations, cash flows or liquidity.
     The Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of the plant. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.
Federal Energy Legislation
     On August 8, 2005, the President signed the Energy Policy Act of 2005 into law. The Act includes a wide range of provisions addressing many aspects of the energy industry. Specifically, with respect to the electric utility industry, the Act includes provisions that, among other things, repeals the Public Utility Holding Company Act of 1935 through enactment of the Public Utility Holding Company Act of 2005, effective as of February 8, 2006, creates incentives for the construction of transmission infrastructure, eliminates the statutory restrictions on ownership of qualifying facilities by electric utilities, establishes civil penalty authority over electric utilities and expands the authority of the FERC to include overseeing the reliability of the bulk power system. While we continue to monitor the impact of this new federal legislation, we cannot predict the impact of this Act on our operations at this time.

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BUSINESS OF SUNCOR DEVELOPMENT COMPANY
     SunCor was incorporated in 1965 under the laws of Arizona and is a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. The principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410, Tempe, Arizona 85281 (telephone 480-317-6800). SunCor and its subsidiaries had approximately 650 employees at December 31, 2007.
     At December 31, 2007, SunCor had total assets of about $670 million. SunCor’s assets consist primarily of land with improvements, commercial buildings, golf courses and other real estate investments. SunCor intends to continue its focus on real estate development of master-planned communities, and mixed-use residential, commercial, office and industrial projects.
     SunCor projects include six master-planned communities and several commercial and residential projects. Four of the master-planned communities and the commercial and residential projects are in Arizona. Other master-planned communities are located in Idaho, New Mexico and Utah.
     SunCor’s operating revenues were approximately $213 million in 2007, $400 million in 2006 and $338 million in 2005. SunCor’s net income was approximately $24 million in 2007, $61 million in 2006 and $56 million in 2005. Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” See Note 22.
     See Note 6 for information regarding SunCor’s long-term debt and “Liquidity and Capital Resources” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of SunCor’s capital requirements.
BUSINESS OF OTHER SUBSIDIARIES
     APSES was incorporated in 1998 under the laws of Arizona and provides energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation, and project management) and competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) to commercial and industrial retail customers in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. APSES had approximately 60 employees as of December 31, 2007. APSES’ principal offices are located at 400 East Van Buren Street, Phoenix, Arizona 85004 (telephone 602-250-5000).
     APSES had a net loss of $4 million in 2007, a net loss of $3 million in 2006 and a net loss of $6 million in 2005. At December 31, 2007, APSES had total assets of $95 million.
     El Dorado was incorporated in 1983 under the laws of Arizona. El Dorado owns minority interests in several energy-related investments and Arizona community-based ventures. El Dorado’s short-term goal is to prudently realize the value of its existing investments. On a long-term basis, Pinnacle West may use El Dorado, when appropriate, for investments that are strategic to the business of generating, distributing and marketing electricity. El Dorado’s offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-3517).

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     El Dorado had a net loss of $6 million in 2007, a net loss of $4 million in 2006 and net income of $4 million in 2005. Income taxes related to El Dorado are recorded by Pinnacle West. At December 31, 2007, El Dorado had total assets of $30 million.
     Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006. Pinnacle West Marketing & Trading had a net loss of $11 million in 2007. At December 31, 2007, Pinnacle West Marketing & Trading had total assets of $73 million.

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SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION
SELECTED CONSOLIDATED FINANCIAL DATA
                                         
    2007     2006     2005     2004     2003  
    (dollars in thousands, except per share amounts)  
OPERATING RESULTS
                                       
Operating revenues:
                                       
Regulated electricity segment
  $ 2,918,163     $ 2,635,036     $ 2,237,145     $ 2,035,247     $ 1,978,075  
Real estate segment
    212,586       399,798       338,031       350,315       361,604  
Marketing and trading
    342,371       330,742       351,558       400,628       391,196  
Other revenues
    48,018       36,172       61,221       42,816       27,929  
 
                             
Total operating revenues
  $ 3,521,138     $ 3,401,748     $ 2,987,955     $ 2,829,006     $ 2,758,804  
 
                             
Income from continuing operations (a)
  $ 301,132     $ 317,143     $ 223,163     $ 246,590     $ 225,384  
Discontinued operations – net of income taxes (b)
    6,011       10,112       (46,896 )     (3,395 )     15,195  
 
                             
Net income
  $ 307,143     $ 327,255     $ 176,267     $ 243,195     $ 240,579  
 
                             
 
                                       
COMMON STOCK DATA
                                       
Book value per share – year-end
  $ 35.15     $ 34.48     $ 34.58     $ 32.14     $ 30.97  
Earnings (loss) per weighted-average common share outstanding:
                                       
Continuing operations – basic
  $ 3.00     $ 3.19     $ 2.31     $ 2.70     $ 2.47  
Net income – basic
  $ 3.06     $ 3.29     $ 1.83     $ 2.66     $ 2.64  
Continuing operations – diluted
  $ 2.99     $ 3.17     $ 2.31     $ 2.69     $ 2.47  
Net income – diluted
  $ 3.05     $ 3.27     $ 1.82     $ 2.66     $ 2.63  
Dividends declared per share
  $ 2.10     $ 2.025     $ 1.925     $ 1.825     $ 1.725  
Weighted-average common shares outstanding – basic
    100,255,807       99,417,008       96,483,781       91,396,904       91,264,696  
Weighted-average common shares outstanding – diluted
100,834,871       100,010,108       96,589,949       91,532,473       91,405,134  
 
                                       
BALANCE SHEET DATA
                                       
Total assets
  $ 11,162,209     $ 10,817,900     $ 10,588,485     $ 9,875,456     $ 9,512,808  
 
                             
Liabilities and equity:
                                       
Current liabilities
  $ 1,344,449     $ 923,338     $ 1,608,863     $ 1,590,460     $ 1,403,012  
Long-term debt less current maturities
    3,127,125       3,232,633       2,608,455       2,584,985       2,616,585  
Deferred credits and other
    3,159,024       3,215,813       2,946,203       2,749,815       2,663,432  
 
                             
Total liabilities
    7,630,598       7,371,784       7,163,521       6,925,260       6,683,029  
Common stock equity
    3,531,611       3,446,116       3,424,964       2,950,196       2,829,779  
 
                             
Total liabilities and equity
  $ 11,162,209     $ 10,817,900     $ 10,588,485     $ 9,875,456     $ 9,512,808  
 
                             
 
(a)   Includes regulatory disallowance of $8 million after tax in 2007 and $84 million after tax in 2005. See Note 3.
 
(b)   Amounts primarily related to Silverhawk and SunCor discontinued operations. See Note 22.

24


 

SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY
                                         
    2007     2006     2005     2004     2003  
    (dollars in thousands)  
OPERATING RESULTS
                                       
Electric operating revenues
  $ 2,936,277     $ 2,658,513     $ 2,270,793     $ 2,197,121     $ 2,104,931  
Fuel and purchased power costs
    1,151,392       969,767       688,982       763,254       703,431  
Operating expenses
    1,358,890       1,290,804       1,200,198       1,104,886       1,103,342  
 
                             
Operating income
    425,995       397,942       381,613       328,981       298,158  
Other income (deductions)
    20,870       27,584       (69,171 )     15,328       26,347  
Interest deductions – net
    162,925       155,796       141,963       144,682       143,568  
 
                             
Net income
  $ 283,940     $ 269,730     $ 170,479     $ 199,627     $ 180,937  
 
                             
 
                                       
BALANCE SHEET DATA
                                       
Total assets
  $ 10,321,402     $ 9,948,766     $ 9,143,643     $ 8,069,564     $ 7,685,718  
 
                             
 
                                       
Liabilities and equity:
                                       
Common stock equity
  $ 3,351,441     $ 3,207,473     $ 2,985,225     $ 2,232,402     $ 2,203,630  
Long-term debt less current maturities
    2,876,881       2,877,502       2,479,703       2,267,094       2,135,606  
 
                             
Total capitalization
    6,228,322       6,084,975       5,464,928       4,499,496       4,339,236  
Current liabilities
    1,055,706       806,556       1,021,084       1,154,702       879,549  
Deferred credits and other
    3,037,374       3,057,235       2,657,631       2,415,366       2,466,933  
 
                             
Total liabilities and equity
  $ 10,321,402     $ 9,948,766     $ 9,143,643     $ 8,069,564     $ 7,685,718  
 
                             

25


 

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 Consolidated Financial Statements and APS’ Financial Statements and the related Notes that appear in Item 8 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 above the national average and remains an important driver of our revenues and earnings.
     Our cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed below under “Liquidity and Capital Resources,” are substantial because of customer growth in APS’ service territory and inflationary impacts on the capital budget, highlighting APS’ need for the timely recovery through rates of these and other expenditures. On June 28, 2007, the ACC issued an order in a general rate case granting APS retail base rate increases. The ACC rate case decision and other retail and wholesale rate matters are discussed in Note 3.
     SunCor, our real estate development subsidiary, has been an important source of earnings in recent years, although SunCor’s earnings in 2007 and expected earnings in 2008 reflect a slowdown in the western United States real estate markets. See discussion below in “Pinnacle West Consolidated – Factors Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APSES, provides energy-related products and services and competitive commodity-related energy services to commercial and industrial retail customers in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures.
     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 energy resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.
     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.

26


 

PINNACLE WEST CONSOLIDATED –
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
     Pinnacle West’s two reportable 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 for the years ended December 31, 2007, 2006 and 2005 and reconciles net income in total (dollars in millions):
                         
    2007     2006     2005  
Regulated electricity segment (a)
  $ 274     $ 259     $ 167  
Real estate segment
    14       50       35  
All other (b)
    13       8       21  
 
                 
Income from continuing operations
    301       317       223  
Discontinued operations – net of tax:
                       
Real estate (c)
    9       10       17  
Sale of Silverhawk (d)
          1       (67 )
All other (b)
    (3 )     (1 )     3  
 
                 
Net income
  $ 307     $ 327     $ 176  
 
                 
 
(a)   Includes an $84 million after-tax regulatory disallowance of plant costs in 2005 in accordance with APS’ 2003 general retail rate case settlement.
 
(b)   Includes activities related to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.
 
(c)   Primarily relates to sales of commercial properties.
 
(d)   See Note 22.
PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS
2007 Compared with 2006
     Our consolidated net income for 2007 was $307 million compared with $327 million for 2006. The current period includes income from discontinued operations of $9 million related to sales of commercial properties by SunCor and a loss from discontinued operations of $3 million related to an APSES project. The prior year includes income from discontinued operations of $10 million related to sales of commercial properties by SunCor. Income from continuing operations decreased $16 million in the year-to-year comparison and is reflected in the segments as follows:

27


 

    Regulated Electricity Segment – Income from continuing operations increased approximately $15 million primarily due to higher retail sales related to customer growth; the effects of weather on retail sales; and impacts of the retail rate increase. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs (including increased maintenance and overhauls and the Palo Verde performance improvement plan), customer service and other costs; higher depreciation and amortization primarily due to increased plant balances; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior year and lower interest income as a result of lower investment balances; and a regulatory disallowance. In addition, higher fuel and purchased power costs related to commodity price increases were substantially offset by deferral of such costs in accordance with the PSA. See Note 3 for further discussion of the regulatory disallowance and the PSA.
 
    Real Estate Segment – Income from continuing operations decreased approximately $36 million primarily due to lower sales of residential property and land parcels resulting from the continued slowdown in the western United States real estate markets.

28


 

     Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2007 compared with the prior year are contained in the following table (dollars in millions):
                 
    Increase (Decrease)  
    Pretax     After Tax  
Regulated electricity segment:
               
Higher retail sales primarily due to customer growth, excluding weather effects
  $ 46     $ 28  
Effects of weather on retail sales
    37       23  
Impacts of retail rate increase effective July 1, 2007:
               
Revenue increase related to higher Base Fuel Rate
    185       113  
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate
    (171 )     (104 )
Non-fuel rate increase
    6       4  
Net changes in fuel and purchased power costs related to price:
               
Higher fuel and purchased power costs related to increased commodity prices
    (121 )     (74 )
Increased deferred fuel and purchased power costs related to increased prices
    115       70  
Mark-to-market fuel and purchased power costs, net of related deferred fuel and purchased power costs
    18       11  
Regulatory disallowance (see Note 3)
    (14 )     (8 )
Operations and maintenance increases primarily due to:
               
Increased generation costs, including increased maintenance and overhauls and Palo Verde performance improvement plan
    (25 )     (15 )
Customer service and other costs
    (21 )     (13 )
Higher depreciation and amortization primarily due to increased plant balances
    (12 )     (7 )
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in prior year
    (15 )     (9 )
Income tax benefits resolved in 2007 related to prior years
          13  
Income tax credits resolved in 2006 related to prior years
          (14 )
Miscellaneous items, net
    6       (3 )
 
           
Increase in regulated electricity segment net income
    34       15  
Lower real estate segment income from continuing operations primarily due to:
               
Lower sales of residential property resulting from the continued slowdown in the western United States real estate markets
    (47 )     (29 )
Lower sales of land parcels
    (12 )     (7 )
Higher other costs
    (1 )      
Higher marketing and trading contribution primarily due to higher mark-to-market gains resulting from changes in forward prices and higher unit margins
    8       5  
Other miscellaneous items, net
    (2 )      
 
           
Decrease in income from continuing operations
  $ (20 )   $ (16 )
 
             
Discontinued operations:
               
Increased commercial property real estate sales
            (1 )
Other discontinued operations
            (3 )
 
             
Decrease in net income
          $ (20 )
 
             

29


 

Regulated Electricity Segment Revenues
     Regulated electricity segment revenues were $283 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:
    a $191 million increase in retail revenues due to a rate increase effective July 1, 2007;
 
    a $60 million increase in retail revenues primarily related to customer growth, excluding weather effects;
 
    a $50 million increase in retail revenues due to the effects of weather;
 
    a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;
 
    a $35 million decrease 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 Note 3); and
 
    a $14 million net increase due to miscellaneous factors.
Real Estate Segment Revenues
     Real estate segment revenues were $187 million lower for the year ended December 31, 2007 compared with the prior year primarily because of:
    a $167 million decrease in residential property sales due to the continued slowdown in western United States real estate markets; and
 
    a $20 million decrease primarily due to lower sales of land parcels.
All Other Revenues
     Marketing and trading revenues were $12 million higher for the year ended December 31, 2007 compared with the prior year primarily because of higher mark-to-market gains resulting from changes in forward prices and higher competitive retail sales volumes in California.
     Other revenues were $12 million higher for the year ended December 31, 2007 compared with the prior year primarily as a result of increased sales by APSES of energy-related products and services.
2006 Compared with 2005
     Our consolidated net income for 2006 was $327 million compared with $176 million for the comparable prior-year period. The prior year included a net loss from discontinued operations of $47 million, which was related to the sale and operations of Silverhawk, partially offset by income from sales of real estate commercial properties at SunCor. Income from continuing operations increased $94 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

30


 

    Regulated Electricity Segment – Income from continuing operations increased approximately $92 million primarily due to an $84 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; income tax credits related to prior years resolved in 2006; and increased other income due to higher interest income on higher investment balances. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; and higher depreciation and amortization primarily due to increased plant asset balances, partially offset by lower depreciation rates. In addition, higher fuel and purchased power costs of $74 million after-tax were partially offset by the deferral of $45 million after-tax of costs in accordance with the PSA.
 
    Real Estate Segment – Income from continuing operations increased approximately $15 million primarily due to increased margins on residential sales and the sale of certain joint venture assets, partially offset by higher general and administrative expenses. Income from discontinued operations decreased $7 million due to lower commercial property sales.
 
    Other – Income from continuing operations decreased approximately $13 million primarily due to lower mark-to-market gains, partially offset by higher unit margins on wholesale sales and competitive retail sales in California.

31


 

Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2006 compared with the prior year are contained in the following table (dollars in millions):
                 
    Increase (Decrease)  
    Pretax     After Tax  
Regulated electricity segment:
               
Higher fuel and purchased power costs
  $ (121 )   $ (74 )
Increased deferred fuel and purchased power costs (deferrals began April 1, 2005)
    73       45  
Higher retail sales volumes due to customer growth, excluding weather effects
    87       53  
Regulatory disallowance of plant costs in 2005, in accordance with APS’ 2003 general retail rate case settlement
    139       84  
Operations and maintenance increases primarily due to:
               
Generation costs, including increased maintenance and overhauls
    (41 )     (25 )
Customer service costs, including regulatory demand-side management programs and planned maintenance
    (16 )     (10 )
Miscellaneous items, net
    3       2  
Higher depreciation and amortization primarily due to increased plant asset balances partially offset by lower depreciation rates
    (11 )     (7 )
Higher other income, net of expense, primarily due to miscellaneous asset sales and increased interest income on higher investment balances
    13       8  
Income tax credits related to prior years resolved in 2006
          14  
Miscellaneous items, net
    (4 )     2  
 
           
Increase in regulated electricity segment net income
    122       92  
Lower marketing and trading contribution primarily related to lower mark-to-market gains, partially offset by higher unit margins on wholesale sales and competitive retail sales in California
    (18 )     (11 )
Higher real estate segment contribution primarily related to increased margins on residential sales and the sale of certain joint venture assets
    25       15  
Miscellaneous items, net
    (5 )     (2 )
 
           
Increase in income from continuing operations
  $ 124       94  
 
             
Discontinued operations:
               
Silverhawk loss in 2005
            68  
Lower commercial property real estate sales
            (7 )
Income in 2005 related to sale of NAC
            (4 )
 
           
Increase in net income
          $ 151  
 
             
Regulated Electricity Segment Revenues
     Regulated electricity segment revenues were $398 million higher for 2006 compared with the prior-year period primarily as a result of:
    a $265 million increase in 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;

32


 

    a $124 million increase in retail revenues related to customer growth, excluding weather effects;
 
    a $6 million increase in Off-System Sales primarily resulting from $12 million of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with APS’ 2003 general retail rate case settlement, partially offset by $6 million of lower Off-System Sales in 2006; and
 
    a $3 million increase due to miscellaneous factors.
Real Estate Segment Revenues
     Real estate segment revenues were $62 million higher for 2006 compared with the prior-year period primarily as a result of:
    a $55 million increase in residential sales due to higher prices and volumes; and
 
    a $7 million increase in commercial real estate sales.
Other Revenues
     Other revenues were $25 million lower for 2006 compared with the prior-year period primarily as a result of decreased sales-related products and services by APSES.
     Marketing and trading revenues were $21 million lower for 2006 compared with the prior-year period primarily as a result of:
    a $20 million decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices;
 
    a $12 million decrease in Off-System Sales due to the absence of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with APS’ 2003 general retail rate case settlement;
 
    a $23 million increase from higher prices on competitive retail sales in California; and
 
    a $12 million decrease due to miscellaneous factors.
LIQUIDITY AND CAPITAL RESOURCES – Pinnacle West Consolidated
     Operating Cash Flows
     Net cash provided by operating activities was $658 million for 2007, compared with $394 million for 2006, an increase in net cash flow of $264 million. This change was primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.

33


 

     Net cash provided by operating activities was $394 million for 2006, compared with $730 million for 2005, a decrease in net cash flow of $336 million. This change was primarily due to an increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
     Investing Cash Flows
     Net cash used for investing activities was $873 million for 2007, compared with $569 million for 2006, a decrease in net cash flow of $304 million.
     This cash flow decrease was primarily due to:
    A decrease in cash provided by investing activities related to proceeds of $208 million received in 2006 from the sale of Silverhawk; and
 
    An increase in cash used for capital expenditures and capitalized interest of $183 million (see table and discussion below).
     The cash flow decreases were partially offset by:
    A decrease of $65 million in cash invested in securities at APS;
 
    An increase of $19 million cash provided by sale of real estate investments; and
 
    A net increase of $3 million due to miscellaneous factors.
     Net cash used for investing activities was $569 million for 2006, compared with $585 million for 2005, an increase in net cash flow of $16 million.
     This cash flow increase was primarily due to:
    Proceeds of $208 million received in 2006 from the sale of Silverhawk; and
 
    Less cash used for capital expenditures (including the 2005 acquisition of the Sundance Plant) and capitalized interest of approximately $72 million (see table and discussion below).
     The cash flow increases were partially offset by:
    An increase of $214 million in cash invested in securities at APS;
 
    A decrease of $43 million in cash provided by sale of real estate investments; and
 
    A net decrease of $7 million due to miscellaneous factors.

34


 

     Financing Cash Flows
     Net cash provided by financing activities was $185 million for 2007, compared with $108 million for 2006, an increase in net cash flow of $77 million.
     This cash flow increase was primarily due to a net increase of $295 million in short-term borrowings to fund day-to-day operations and liquidity needs.
     The cash flow increases were partially offset by:
    A decrease of $161 million in net new long-term debt (issuances net of redemptions and refinancing) to fund our construction program and for other general corporate purposes; and
 
    A net decrease of $57 million due to miscellaneous factors.
     Net cash provided by financing activities was $108 million for 2006, compared with net cash used for financing activities in 2005 of $155 million, an increase in net cash flow of $263 million.
     This cash flow increase was primarily due to:
    An increase of $429 million in net new long-term debt (issuances net of redemptions and refinancing) to fund our construction program and for other general corporate purposes;
 
    A net increase of $56 million in short-term borrowings to fund day-to-day operations and liquidity needs; and
 
    A net increase of $37 million due to miscellaneous factors.
     The cash flow increases were partially offset by:
    A decrease of $259 million related to common stock issuance, primarily due to a 2005 public offering.
     Liquidity
     Capital Expenditure Requirements
     The following table summarizes the actual capital expenditures for 2005, 2006 and 2007 and estimated capital expenditures for the next three years:

35


 

CAPITAL EXPENDITURES
(dollars in millions)
                                                 
    Actual     Estimated  
    2005     2006     2007     2008     2009     2010  
APS
                       
Distribution
  $ 325     $ 357     $ 372     $ 410     $ 440     $ 430  
Generation (a)
    356       176       353       380       390       380  
Transmission
    92       113       138       220       320       290  
Other (b)
    36       16       37       50       40       50  
 
                                   
Subtotal
    809       662       900       1,060       1,190       1,150  
SunCor (c)
    106       201       161       100       90       100  
Other
    13       7       3       20       20       10  
 
                                   
Total
  $ 928     $ 870     $ 1,064     $ 1,180     $ 1,300     $ 1,260  
 
                                   
 
(a)   Includes $185 million in 2005 for the acquisition of the Sundance Plant.
 
(b)   Primarily information systems and facilities projects.
 
(c)   Consists primarily of capital expenditures for residential, land development and retail and office building construction reflected in “Real estate investments” and “Capital expenditures” on the Consolidated Statements of Cash Flows.
     Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. In addition, these amounts do not include any impacts from the recent changes in the line extension policy (see Note 3). Major transmission projects are driven by regional customer growth.
     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants. 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. Installation of new steam generators in Palo Verde Unit 3 was completed in the fourth quarter of 2007 at an approximate cost of $70 million (APS’ share), which completed the steam generator replacement program for all three units. Environmental expenditures are estimated at approximately $70 million to $120 million per year for 2008, 2009 and 2010. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require additional environmental expenditures. (See “Business of Arizona Public Service Company — Environmental Matters — Regional Haze Rules” in Item 1.) Generation also includes nuclear fuel expenditures of approximately $90 million to $120 million per year for 2008, 2009 and 2010.
     Capital expenditures will be funded with internally generated cash and/or external financings, which may include issuances of long-term debt and Pinnacle West common stock.

36


 

     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.
     On January 23, 2008, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on March 3, 2008, to shareholders of record on February 1, 2008.
     Our primary sources of cash are dividends from APS, external debt and equity financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2005 through 2007, total dividends from APS were $510 million and total distributions from SunCor were $70 million. For 2007, cash contributions from APS were $170 million and distributions from SunCor were $10 million. 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 December 31, 2007, APS’ common equity ratio, as defined, was approximately 54%.
     At December 31, 2007, Pinnacle West’s outstanding long-term debt, including current maturities, was $175 million. Pinnacle West has a $300 million revolving credit facility that terminates in December 2010. This line of credit is available to support the issuance of up to $250 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit. At December 31, 2007, Pinnacle West had no borrowings outstanding under its revolving line of credit. At December 31, 2007, we had $115 million of commercial paper outstanding.
     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 plan asset performance and plan actuarial assumptions. We contributed approximately $52 million in 2007. The contribution to our pension plan in 2008 is estimated to be approximately $50 million. The expected contribution to our other postretirement benefit plans in 2008 is estimated to be approximately $20 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.
     Significant Financing Activities — 2007. 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.

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     In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.
     Significant Financing Activities —2006. In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk.
     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).
     On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.
     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, equity infusions from Pinnacle West 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. As noted above, in May 2007, Pinnacle West infused approximately $40 million of equity into APS.
     APS’ outstanding long-term debt, including current maturities, was approximately $2.9 billion at December 31, 2007. APS has two committed lines of credit totaling $900 million that are available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit. The $400 million line terminates in December 2010 and the $500 million line terminates in September 2011. At December 31, 2007, APS had borrowings of $218 million under its revolving line of credit. The amount drawn was used for general corporate purposes.
     Significant Financing Activities —2007. 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 October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.
     Significant Financing Activities —2006. On August 3, 2006, APS issued $400 million of debt as follows: $250 million of its 6.25% Notes due 2016 and $150 million of its 6.875% Notes due 2036. A portion of the proceeds was used to pay at maturity approximately $84 million of APS’

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6.75% Senior Notes due November 15, 2006. The remainder was used to fund its construction program and other general corporate purposes.
     On September 28, 2006, APS put in place the $500 million revolving credit facility that terminates in September 2011. APS may increase the amount of the facility up to a maximum facility of $600 million upon the satisfaction of certain conditions. APS will use the facility for general corporate purposes. The facility can also be used for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.
     Other Financing Matters — See Note 3 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 annual and, if necessary, periodic PSA adjustments.
     See “Cash Flow Hedges” in Note 18 for information related to decreased collateral provided to us by counterparties and the change in our margin account.
     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 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.
     SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60 million, of which $48 million was outstanding at December 31, 2007. The loan matures on April 19, 2009, and may be extended one year if certain conditions are met.
     On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan matures on July 31, 2009, and may be extended annually up to two years.
     SunCor’s total outstanding debt was approximately $246 million as of December 31, 2007, including $94 million of debt classified as current maturities of long-term debt under revolving lines of credit totaling $170 million. SunCor’s long-term debt, including current maturities, was $238 million and total short-term debt was $8 million at December 31, 2007. See Note 6.
     El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
     APSES expects minimal capital expenditures over the next three years.
     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

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Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2007, the ratio was approximately 50% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.7 times under APS’ bank financing agreements as of December 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, our bank financial agreements contain a pricing grid in which the interest costs we pay are determined by our current credit ratings.
     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 6 for further discussions.
     Credit Ratings
     The ratings of securities of Pinnacle West and APS as of February 25, 2008 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, natural gas transportation, fuel supply, and other energy-related contracts.
             
    Moody’s   Standard & Poor’s   Fitch
Pinnacle West
           
Senior unsecured (a)
  Baa3 (P)   BB+ (prelim)   N/A
Commercial paper
  P-3   A-3   F3
Outlook
  Negative   Stable   Negative
 
           
APS
           
Senior unsecured
  Baa2   BBB-   BBB
Secured lease obligation bonds
  Baa2   BBB-   BBB
Commercial paper
  P-2   A-3   F3
Outlook
  Negative   Stable   Stable

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(a)   Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.
     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 (see Note 9).
     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 December 31, 2007, APS would have been required to assume approximately $194 million of debt and pay the equity participants approximately $170 million.
     Guarantees and Letters of Credit
     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 and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related products and commodity energy. 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 Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. 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 21 for additional information regarding guarantees and letters of credit.

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Contractual Obligations
     The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2007 (dollars in millions):
                                         
            2009-     2011-              
    2008     2010     2012     Thereafter     Total  
Long-term debt payments, including interest: (a)
                                       
APS
  $ 158     $ 537     $ 1,038     $ 3,135     $ 4,868  
SunCor
    173       78       2       2       255  
Pinnacle West
    10       21       177             208  
 
                             
Total long-term debt payments, including interest
    341       636       1,217       3,137       5,331  
 
                             
Short-term debt payments, including interest (b)
    342                         342  
Purchased power and fuel commitments (c)
    418       651       434       1,584       3,087  
Operating lease payments
    79       148       133       195       555  
Nuclear decommissioning funding requirements
    21       46       49       210       326  
Purchase obligations (d)
    99       29       2       91       221  
Uncertain tax positions
    203       12                   215  
 
                             
Total contractual commitments
  $ 1,503     $ 1,522     $ 1,835     $ 5,217     $ 10,077  
 
                             
 
(a)   The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using the rates at December 31, 2007 (see Note 6).
 
(b)   The short-term debt is primarily related to APS bank borrowings under its revolving line of credit and commercial paper at Pinnacle West (see Note 5).
 
(c)   Our purchased power and fuel commitments include purchases of coal, electricity, natural gas and nuclear fuel (see Note 11).
 
(d)   These contractual obligations include commitments for capital expenditures and other obligations.
CRITICAL ACCOUNTING POLICIES
     In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

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Regulatory Accounting
     Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. A major component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery 90% of the difference between actual retail fuel and power costs and the amount of such costs currently included in base rates. We had $625 million, including $111 million related to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31, 2007.
     Also included in the balance of regulatory assets at December 31, 2007 is a regulatory asset of $338 million in accordance with SFAS No. 158 for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.
     In addition, we had $643 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2007, which primarily are related to removal costs. See Notes 1 and 3 for more information.
Pensions and Other Postretirement Benefit Accounting
     Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
     The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2007 reported pension liability on the Consolidated Balance Sheets and our 2007 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

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    Increase (Decrease)
    Impact on   Impact on
    Pension   Pension
Actuarial Assumption (a)   Liability   Expense
Discount rate:
               
Increase 1%
  $ (213 )   $ (5 )
Decrease 1%
    243       9  
Expected long-term rate of return on plan assets:
               
Increase 1%
          (6 )
Decrease 1%
          6  
 
(a)   Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
     The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2007 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2007 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
                 
    Increase (Decrease)
    Impact on Other   Impact on Other
    Postretirement Benefit   Postretirement
Actuarial Assumption (a)   Obligation   Benefit Expense
Discount rate:
               
Increase 1%
  $ (90 )   $ (4 )
Decrease 1%
    105       5  
Health care cost trend rate (b):
               
Increase 1%
    94       7  
Decrease 1%
    (76 )     (5 )
Expected long-term rate of return on plan assets — pretax:
               
Increase 1%
          (2 )
Decrease 1%
          2  
 
(a)   Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
 
(b)   This assumes a 1% change in the initial and ultimate health care cost trend rate.
     See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
     Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we

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use accrual accounting (for contracts designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)).
     The fair value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. See “Market Risks — Commodity Price Risk” below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative and energy trading accounting.
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 but do not expect it to have a material impact on our financial statements.
     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 but do not expect it to have a material impact on our financial statements.
     See Notes 18 and S-3 for a discussion of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), which we adopted January 1, 2008.
     See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007.
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 2005 through 2007, retail electric revenues comprised approximately 84% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer growth, variations in weather from period to period, customer mix, average usage per customer, electricity rates and tariffs and the recovery of PSA deferrals. 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 they are credited to APS’

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retail customers through the PSA. These revenue transactions are affected by the availability of excess economic generation or other energy resources and wholesale market conditions, including demand and prices. Competitive retail sales of energy and energy-related products and services are made by APSES in certain western states that have opened to competition.
     Rate Proceedings Our cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed above under “Liquidity and Capital Resources,” are substantial because of customer growth in APS’ service territory and inflationary impacts on the capital budget, highlighting APS’ need for the timely recovery through rates of these and other expenditures. On June 28, 2007, the ACC issued an order in a general rate case granting APS retail base rate increases. The ACC rate case decision and other retail and wholesale rate matters are discussed in Note 3.
     Fuel and Purchased Power Costs Fuel and purchased power costs included on our Consolidated Statements of Income 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 “PSA Modifications” and “2006 Deferrals” in Note 3 for information regarding the PSA, including the 2006 Deferrals. APS’ recovery of PSA deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.
     Customer and Sales Growth The customer and sales growth referred to in this paragraph apply to Native Load customers and sales to them. Customer growth in APS’ service territory was 3.3% during 2007. Customer growth averaged 4.0% a year for the three years 2005 through 2007; and we currently expect customer growth to decline, averaging about 1% to 2% per year for 2008 through 2010 due to factors reflecting the economic conditions both nationally and in Arizona. For the three years 2005 through 2007, APS’ actual retail electricity sales in kilowatt-hours grew at an average annual rate of 4.8%; adjusted to exclude the effects of weather variations, such retail sales growth averaged 3.8% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 1% to 2% on average per year, during 2008 through 2010, excluding the effects of weather variations. We currently expect our retail sales growth in 2008 to be below average because of potential effects on customer usage from the economic conditions mentioned above and retail rate increases (see Note 3).
     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.

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     Wholesale Market 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. See “Rate Requests for Transmission and Ancillary Services” in Note 3 for information regarding APS’ recent filing with the FERC requesting an increase in transmission rates.
Other Factors Affecting Financial Results
     Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), 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 (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditures” above for information regarding planned additions to our facilities.
     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, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.3% of the assessed value for 2007, 8.9% of assessed value for 2006 and 9.2% for 2005. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities) and as we improve our existing facilities. See “Capital Expenditures” above for information regarding planned additions to our facilities.
     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 electric service providers providing unbundled energy or other utility services to APS’ customers. We cannot predict when, and the extent to which, additional electric service providers will re-enter APS’ service territory.
     Subsidiaries SunCor’s net income was $24 million in 2007, $61 million in 2006 and $56 million in 2005. See Note 17 for further discussion. We currently expect SunCor’s net income in 2008 to be approximately $20 million. This estimate reflects continuation of the slowdown in the western United States real estate markets.
     The historical results of APSES, Pinnacle West Marketing & Trading and El Dorado are not indicative of future performance.
     General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” below for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.

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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 decommissioning trust fund (see Note 12). 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.
     The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2007 and 2006. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2007 and 2006 (dollars in thousands):
                                                 
                    Variable-Rate     Fixed-Rate  
    Short-Term Debt     Long-Term Debt     Long-Term Debt  
    Interest             Interest             Interest        
2007   Rates     Amount     Rates     Amount     Rates     Amount  
2008
    5.54 %   $ 340,661       7.33 %   $ 159,337       4.65 %   $ 4,436  
2009
                7.20 %     71,054       5.76 %     1,050  
2010
                9.20 %     201       5.71 %     1,104  
2011
                8.91 %     2,284       6.23 %     576,218  
2012
                9.50 %     103       6.50 %     376,293  
Years thereafter
                3.77 %     567,239       5.64 %     1,540,462  
 
                                         
Total
          $ 340,661             $ 800,218             $ 2,499,563  
 
                                         
Fair value
          $ 340,661             $ 800,218             $ 2,414,301  
 
                                         

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                    Variable-Rate     Fixed-Rate  
    Short-Term Debt     Long-Term Debt     Long-Term Debt  
    Interest             Interest             Interest        
2006   Rates     Amount     Rates     Amount     Rates     Amount  
2007
    6.26 %   $ 35,750       10.25 %   $ 112       5.78 %   $ 1,549  
2008
                7.26 %     161,356       5.39 %     7,810  
2009
                9.37 %     2,500       6.23 %     5,371  
2010
                            6.24 %     6,455  
2011
                            6.24 %     576,320  
Years thereafter
                3.77 %     565,855       5.81 %     1,916,758  
 
                                         
Total
          $ 35,750             $ 729,823             $ 2,514,263  
 
                                         
Fair Value
          $ 35,750             $ 729,823             $ 2,480,605  
 
                                         
     The tables below present contractual balances of APS’ long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2007 and 2006. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2007 and 2006 (dollars in thousands):
                                                 
                    Variable-Rate     Fixed-Rate  
    Short-Term Debt     Long-Term Debt     Long-Term Debt  
    Interest             Interest             Interest        
2007   Rates     Amount     Rates     Amount     Rates     Amount  
2008
    5.36 %   $ 218,000           $       5.66 %   $ 978  
2009
                            5.60 %     934  
2010
                            5.59 %     1,012  
2011
                            6.37 %     401,208  
2012
                            6.50 %     376,293  
Years thereafter
                3.76 %     565,855       5.64 %     1,540,462  
 
                                         
Total
          $ 218,000             $ 565,855             $ 2,320,887  
 
                                         
Fair value
          $ 218,000             $ 565,855             $ 2,235,624  
 
                                         

49


 

                                 
    Variable-Rate     Fixed-Rate  
    Long-Term Debt     Long-Term Debt  
    Interest             Interest        
2006   Rates     Amount     Rates     Amount  
2007
        $       6.18 %   $ 1,033  
2008
                6.18 %     1,230  
2009
                6.17 %     1,020  
2010
                6.17 %     1,111  
2011
                6.38 %     401,320  
Years thereafter
    3.77 %     565,855       5.81 %     1,916,758  
 
                           
Total
          $ 565,855             $ 2,322,472  
 
                           
Fair Value
          $ 565,855             $ 2,288,814  
 
                           
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. 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. 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. 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.
     The following tables show the net pretax changes in mark-to-market of our derivative positions in 2007 and 2006 (dollars in millions):
                 
    2007     2006  
Mark-to-market of net positions at beginning of year
  $ 15     $ 516  
Recognized in earnings:
               
Change in mark-to-market losses for future period deliveries
    (2 )     (27 )
Mark-to-market gains realized including ineffectiveness during the period
    (15 )     (3 )
Decrease (increase) in regulatory asset
    55       (93 )
Recognized in OCI:
               
Change in mark-to-market losses for future period deliveries (a)
    (1 )     (352 )
Mark-to-market gains realized during the period
    (12 )     (26 )
Change in valuation techniques
           
 
           
Mark-to-market of net positions at end of year
  $ 40     $ 15  
 
           
 
(a)   The decreases in mark-to-market recorded in OCI are due primarily to decreases in forward natural gas prices.

50


 

     The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2007 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” for more discussion of our valuation methods.
                                                         
                                                    Total  
                                            Years     fair  
Source of Fair Value   2008     2009     2010     2011     2012     thereafter     value  
Prices actively quoted
  $ (12 )   $ 10     $ 14     $ 2     $     $     $ 14  
Prices provided by other external sources
    (4 )     (16 )     1       4       3             (12 )
Prices based on models and other valuation methods
    12       15       (1 )           2       10       38  
 
                                         
Total by maturity
  $ (4 )   $ 9     $ 14     $ 6     $ 5     $ 10     $ 40  
 
                                         
     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 Consolidated Balance Sheets at December 31, 2007 and 2006 (dollars in millions).
                                 
    December 31, 2007     December 31, 2006  
    Gain (Loss)     Gain (Loss)  
    Price Up 10%     Price Down 10%     Price Up 10%     Price Down 10%  
Mark-to-market changes reported in:
                               
Earnings
                               
Electricity
  $ 3     $ (3 )   $     $  
Natural gas
    4       (4 )            
Regulatory asset (liability) or OCI (a)
                               
Electricity
    45       (45 )     38       (38 )
Natural gas
    85       (85 )     80       (80 )
 
                       
Total
  $ 137     $ (137 )   $ 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. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.
Credit Risk
     We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 1, “Derivative Accounting” for a discussion of our credit valuation adjustment policy. See Note 18 for further discussion of credit risk.

51


 

ARIZONA PUBLIC SERVICE COMPANY — RESULTS OF OPERATIONS
Regulatory Matters
     See “Pinnacle West Consolidated — Results of Operations — Regulatory Matters” above for information about the ACC’s order in APS’ general retail rate case and the PSA.
2007 Compared with 2006
     Our net income for 2007 was $284 million compared with $270 million for 2006. APS’ net income increased approximately $14 million primarily due to higher retail sales related to customer growth; the effects of weather on retail sales; and impacts of the retail rate increase. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs (including increased maintenance and overhauls and the Palo Verde performance improvement plan), customer service and other costs; higher depreciation and amortization primarily due to increased plant balances; higher interest expense due to higher debt balances and higher rates; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior year and lower interest income as a result of lower investment balances; and a regulatory disallowance (see Note 3). In addition, higher fuel and purchased power costs related to commodity price increases were partially offset by the deferral of such costs in accordance with the PSA. See Note 3 for further discussion.
     Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2007 compared with the prior year are contained in the following table (dollars in millions):

52


 

                 
    Increase (Decrease)  
    Pretax     After Tax  
Higher retail sales primarily due to customer growth, excluding weather effects
  $ 46     $ 28  
Effects of weather on retail sales
    37       23  
Impacts of retail rate increase effective July 1, 2007:
               
Revenue increase related to higher Base Fuel Rate
    185       113  
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate
    (171 )     (104 )
Non-fuel rate increase
    6       4  
Net changes in fuel and purchased power costs related to price:
               
Higher fuel and purchased power costs related to increased commodity prices
    (121 )     (74 )
 
               
Increased deferred fuel and purchased power costs related to increased prices
    115       70  
Mark-to-market fuel and purchased power costs, net of related deferred fuel and purchased power costs
    18       11  
Regulatory disallowance (see Note 3)
    (14 )     (8 )
Operations and maintenance increases primarily due to:
               
Increased generation costs, including increased maintenance and overhauls and Palo Verde performance improvement plan
    (25 )     (15 )
Customer service and other costs
    (19 )     (11 )
Higher depreciation and amortization primarily due to increased plant balances
    (12 )     (7 )
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in prior year
    (7 )     (4 )
Income tax benefits resolved in 2007 related to prior years
          11  
Income tax credits resolved in 2006 related to prior years
          (11 )
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates
    (7 )     (4 )
Lower marketing and trading contribution primarily due to lower mark-to-market gains because of changes in forward prices
    (7 )     (4 )
Other miscellaneous items, net
    2       (4 )
 
           
Increase in net income
  $ 26     $ 14  
 
           
     Electric operating revenues were $278 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:
    a $191 million increase in retail revenues due to a rate increase effective July 1, 2007;
 
    a $60 million increase in retail revenues primarily related to customer growth, excluding weather effects;
 
    a $50 million increase in retail revenues due to the effects of weather;

53


 

    a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;
 
    a $35 million decrease 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 Note 3); and
 
    a $9 million net increase due to miscellaneous factors.
2006 Compared with 2005
     APS’ net income for 2006 was $270 million compared with $170 million for the comparable prior year. The $100 million increase was primarily due to an $84 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; higher marketing and trading gross margin primarily due to higher mark-to-market gains; income tax credits related to prior years resolved in 2006; and increased other income due to higher interest income on higher investment balances. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; higher depreciation and amortization primarily due to increased plant asset balances, partially offset by lower depreciation rates; and higher interest expense. In addition, higher fuel and purchased power costs of $74 million after-tax were partially offset by the deferral of $45 million after-tax costs in accordance with the PSA.

54


 

     Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2006 compared with the year ended December 31, 2005 are contained in the following table (dollars in millions):
                 
    Increase (Decrease)  
    Pretax     After Tax  
Higher fuel and purchased power costs (see Note 3)
  $ (121 )   $ (74 )
Higher retail sales volumes due to customer growth, excluding weather effects
    87       53  
Increased deferred fuel and purchased power costs (deferrals began April 1, 2005)
    73       45  
Absence of prior-year cost-based contract for PWEC Dedicated Assets (see Note 3)
    56       34  
Higher marketing and trading gross margin primarily related to higher mark-to-market gains
    20       12  
Regulatory disallowance of plant costs in 2005, in accordance with APS’ 2003 general retail rate case settlement
    139       84  
Operations and maintenance increases primarily due to:
               
Generation costs, including increased maintenance and overhauls
    (41 )     (25 )
Costs of PWEC Dedicated Assets not included in prior year
    (18 )     (11 )
Customer service costs, including regulatory demand-side management programs and planned maintenance
    (16 )     (10 )
Miscellaneous items, net
    1       1  
Depreciation and amortization increases primarily due to:
               
Higher depreciable assets due to transfer of PWEC Dedicated Assets (see Note 3)
    (14 )     (8 )
Higher other depreciable assets partially offset by lower depreciation rates
    (14 )     (8 )
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates
    (14 )     (8 )
Higher other income, net of expense, primarily due to miscellaneous asset sales and increased interest income on higher investment balances
    9       5  
Income tax credits related to prior years resolved in 2006
          11  
Miscellaneous items, net
    (7 )     (1 )
 
           
Increase in net income
  $ 140     $ 100  
 
           
     Electric operating revenues were $388 million higher for 2006 compared with the prior year primarily as a result of:
    a $265 million increase in 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;
 
    a $124 million increase in retail revenues related to customer growth, excluding weather effects; and
 
    a $1 million decrease due to miscellaneous factors.

55


 

LIQUIDITY AND CAPITAL RESOURCES — ARIZONA PUBLIC SERVICE COMPANY
     Operating Cash Flows
     Net cash provided by operating activities was $766 million for 2007, compared with $394 million for 2006, an increase in net cash flow of $372 million. This change was primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
     Net cash provided by operating activities was $394 million for 2006, compared with $722 million for 2005, a decrease in net cash flow of $328 million. This change was primarily due to an increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
     Investing Cash Flows
     Net cash used for investing activities was $881 million for 2007, compared with $714 million for 2006, a decrease in net cash flow of $167 million.
     This cash flow decrease was primarily due to:
    An increase of $239 million in cash used for capital expenditures and allowance for borrowed funds used during construction (see table and discussion above).
     The cash flow decrease was partially offset by:
    A decrease of $65 million in cash invested in securities; and
 
    A net increase of $7 million due to miscellaneous factors.
     Net cash used for investing activities was $714 million for 2006, compared with $645 million for 2005, a decrease in net cash flow of $69 million.
     This cash flow decrease was primarily due to:
    A decrease of $500 million related to repayment in 2005 by PWEC of a loan;
 
    An increase of $214 million in cash invested in securities; and
 
    A net decrease of $1 million due to miscellaneous factors.
     The cash flow decreases were partially offset by:
    Less cash used for capital expenditures (including, in 2005, the acquisition of the PWEC Dedicated Assets and the Sundance Plant) and allowance for borrowed funds used during construction of $646 million (see table and discussion above).

56


 

     Financing Cash Flows
     Net cash provided by financing activities was $86 million for 2007, compared with $352 million for 2006, a decrease in net cash flow of $266 million.
     The cash flow decrease was primarily due to:
    A decrease of $311 million in net new long-term debt (issuances net of redemptions and refinancing) to fund APS’ construction program and for general corporate purposes; and
 
    A decrease of $173 million due to decreased equity infusions from Pinnacle West.
     The cash flow decreases were partially offset by:
    A net increase of $218 million in short-term borrowings to fund day-to-day operations and liquidity needs.
     Net cash provided by financing activities was $352 million for 2006, compared with net cash used for financing activities in 2005 of $76 million, an increase in net cash flow of $428 million.
     This cash flow increase was primarily due to:
    An increase of $466 million in net new long-term debt (issuances net of redemptions and refinancings) in order to fund our construction program and for other general corporate purposes.
     This cash flow increase was partially offset by:
    A decrease of $37 million due to decreased equity infusions from Pinnacle West; and
 
    A net decrease of $1 million due to miscellaneous factors.
     Liquidity
     For additional discussion see “Liquidity and Capital Resources — Pinnacle West Consolidated.”

57


 

     Contractual Obligations
     The following table summarizes contractual requirements for APS as of December 31, 2007 (dollars in millions):
                                         
            2009-     2011-     There-        
    2008     2010     2012     after     Total  
Long-term debt payments, including interest (a)
  $ 158     $ 537     $ 1,038     $ 3,135     $ 4,868  
Short-term debt payments, including interest
    219                         219  
Purchased power and fuel commitments (b)
    375       651       422       1,584       3,032  
Operating lease payments
    72       136       124       177       509  
Nuclear decommissioning funding requirements
    21       46       49       210       326  
Purchase obligations (c)
    99       29       2       91       221  
Uncertain tax positions
    198       12                   210  
 
                             
Total contractual commitments
  $ 1,142     $ 1,411     $ 1,635     $ 5,197     $ 9,385  
 
                             
 
(a)   The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by the rates at December 31, 2007 (see Note 6).
 
(b)   APS’ purchased power and fuel commitments include purchases of coal, electricity, natural gas, and nuclear fuel (see Note 11).
 
(c)   These contractual obligations include commitments for capital expenditures and other obligations.

58


 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
         
    Page  
    60  
    61  
    63  
    64  
    66  
    67  
    68  
 
       
    118  
    119  
    121  
    122  
    124  
    125  
    127  
 
       
Financial Statement Schedules for 2007, 2006 and 2005
       
    137  
    138  
    139  
    140  
    141  
See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.

59


 

MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)
     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007. The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s consolidated financial statements.
February 27, 2008

60


 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

61


 

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As reflected in the consolidated statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans effective December 31, 2006.

As discussed in Note 23, the Company adopted the provisions of FASB Staff Position No. FIN 39-1. Also, as discussed in Note 22, SunCor entered into an agreement in the first quarter of 2008 to sell certain commercial properties and, accordingly, reclassified the related operating results to discontinued operations on the 2007 Consolidated Statement of Income in accordance with SFAS 144.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 27, 2008
(November 25, 2008 as to (1) the effects of the adoption of FASB Staff Position No. FIN 39-1 as described in Note 23, and (2) the effects of discontinued operations related to SunCor as described in Note 22).

62


 

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME

(dollars and shares in thousands, except per share amounts)
                         
    Year Ended December 31,  
    2007     2006     2005  
OPERATING REVENUES
                       
Regulated electricity segment
  $ 2,918,163     $ 2,635,036     $ 2,237,145  
Real estate segment
    212,586       399,798       338,031  
Marketing and trading
    342,371       330,742       351,558  
Other revenues
    48,018       36,172       61,221  
 
                 
Total
    3,521,138       3,401,748       2,987,955  
 
                 
OPERATING EXPENSES
                       
Regulated electricity segment fuel and purchased power
    1,140,923       960,649       595,141  
Real estate segment operations
    192,972       324,861       278,366  
Marketing and trading fuel and purchased power
    294,236       290,637       293,091  
Operations and maintenance
    734,705       691,277       635,827  
Depreciation and amortization
    372,128       358,644       347,652  
Taxes other than income taxes
    128,218       128,395       132,040  
Other expenses
    38,925       28,415       51,987  
Regulatory disallowance (Note 3)
                138,562  
 
                 
Total
    2,902,107       2,782,878       2,472,666  
 
                 
OPERATING INCOME
    619,031       618,870       515,289  
 
                 
OTHER
                       
Allowance for equity funds used during construction
    21,195       14,312       11,191  
Other income (Note 19)
    24,694       44,016       23,360  
Other expense (Note 19)
    (25,883 )     (27,800 )     (26,716 )
 
                 
Total
    20,006       30,528       7,835  
 
                 
INTEREST EXPENSE
                       
Interest charges
    208,521       196,826       185,087  
Capitalized interest
    (23,063 )     (20,989 )     (12,018 )
 
                 
Total
    185,458       175,837       173,069  
 
                 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    453,579       473,561       350,055  
INCOME TAXES (Note 4)
    152,447       156,418       126,892  
 
                 
INCOME FROM CONTINUING OPERATIONS
    301,132       317,143       223,163  
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
                       
Net of income tax expense (benefit) of $4,045, $6,570 and ($29,797)
    6,011       10,112       (46,896 )
 
                 
NET INCOME
  $ 307,143     $ 327,255     $ 176,267  
 
                 
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC
    100,256       99,417       96,484  
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED
    100,835       100,010       96,590  
EARNINGS PER WEIGHTED — AVERAGE COMMON SHARE OUTSTANDING
                       
 
                       
Income from continuing operations — basic
  $ 3.00     $ 3.19     $ 2.31  
Net income — basic
    3.06       3.29       1.83  
Income from continuing operations — diluted
    2.99       3.17       2.31  
Net income — diluted
    3.05       3.27       1.82  
DIVIDENDS DECLARED PER SHARE
  $ 2.10     $ 2.025     $ 1.925  
See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS

(dollars in thousands)
                 
    December 31,  
    2007     2006  
ASSETS
               
 
               
CURRENT ASSETS
               
Cash and cash equivalents
  $ 56,321     $ 87,210  
Investment in debt securities
          32,700  
Customer and other receivables
    456,007       501,628  
Allowance for doubtful accounts
    (4,782 )     (5,597 )
Materials and supplies (at average cost)
    149,759       125,802  
Fossil fuel (at average cost)
    27,792       21,973  
Deferred income taxes (Note 4)
    31,510       982  
Assets from risk management and trading activities (Note 18)
    57,605       112,547  
Home inventory (Note 1)
    98,729       41,846  
Other current assets
    33,988       17,090  
 
           
Total current assets
    906,929       936,181  
 
           
 
               
INVESTMENTS AND OTHER ASSETS
               
Real estate investments — net (Notes 1 and 6)
    532,600       526,008  
Assets from long-term risk management and trading activities (Note 18)
    48,928       67,649  
Decommissioning trust accounts (Note 12)
    379,347       343,771  
Other assets
    117,941       111,388  
 
           
Total investments and other assets
    1,078,816       1,048,816  
 
           
 
               
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
               
Plant in service and held for future use
    11,640,739       11,154,919  
Less accumulated depreciation and amortization
    4,004,944       3,797,475  
 
           
Net
    7,635,795       7,357,444  
Construction work in progress
    625,577       368,284  
Intangible assets, net of accumulated amortization of $252,122 and $218,836
    105,746       96,100  
Nuclear fuel, net of accumulated amortization of $68,375 and $50,741
    69,271       60,100  
 
           
Total property, plant and equipment
    8,436,389       7,881,928  
 
           
 
               
DEFERRED DEBITS
               
Deferred fuel and purchased power regulatory asset (Notes 1, 3 and 4)
    110,928       160,268  
Other regulatory assets (Notes 1, 3 and 4)
    514,353       686,016  
Other deferred debits
    114,794       104,691  
 
           
Total deferred debits
    740,075       950,975  
 
           
 
               
TOTAL ASSETS
  $ 11,162,209     $ 10,817,900  
 
           
See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS

(dollars in thousands)
                 
    December 31,  
    2007     2006  
LIABILITIES AND COMMON STOCK EQUITY
               
 
               
CURRENT LIABILITIES
               
Accounts payable
  $ 323,346     $ 346,047  
Accrued taxes
    269,628       263,935  
Accrued interest
    39,836       48,746  
Short-term borrowings (Note 5)
    340,661       35,750  
Current maturities of long-term debt (Note 6)
    163,773       1,596  
Customer deposits
    80,010       70,168  
Liabilities from risk management and trading activities (Note 18)
    24,510       77,064  
Other current liabilities
    102,685       80,032  
 
           
Total current liabilities
    1,344,449       923,338  
 
           
 
               
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)
    3,127,125       3,232,633  
 
           
 
               
DEFERRED CREDITS AND OTHER
               
Deferred income taxes (Note 4)
    1,243,743       1,225,798  
Regulatory liabilities (Notes 1, 3 and 4)
    642,564       635,431  
Liability for asset retirements (Note 12)
    281,903       268,389  
Liabilities for pension and other postretirement benefits (Note 8)
    504,603       588,852  
Liabilities from risk management and trading activities (Note 18)
    4,701       68,349  
Unamortized gain — sale of utility plant (Note 9)
    36,606       41,182  
Other
    444,904       387,812  
 
           
Total deferred credits and other
    3,159,024       3,215,813  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
               
 
               
COMMON STOCK EQUITY (Note 7)
               
Common stock, no par value; authorized 150,000,000 shares; issued 100,525,470 at end of 2007 and 99,961,066 at end of 2006
    2,135,787       2,114,550  
Treasury stock at cost; 39,505 shares at end of 2007 and 2,419 shares at end of 2006
    (2,054 )     (449 )
 
           
Total common stock
    2,133,733       2,114,101  
 
           
Accumulated other comprehensive income (loss):
               
Pension and other postretirement benefits (Note 8)
    (39,336 )     (19,263 )
Derivative instruments
    23,473       31,531  
 
           
Total accumulated other comprehensive income
    (15,863 )     12,268  
 
           
Retained earnings
    1,413,741       1,319,747  
 
           
Total common stock equity
    3,531,611       3,446,116  
 
           
 
TOTAL LIABILITIES AND COMMON STOCK EQUITY
  $ 11,162,209     $ 10,817,900  
 
           
See Notes to Pinnacle West’s Consolidated Financial Statements.

65


 

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)
                         
    Year Ended December 31,  
    2007     2006     2005  
CASH FLOWS FROM OPERATING ACTIVITIES
                       
Net Income
  $ 307,143     $ 327,255     $ 176,267  
Adjustments to reconcile net income to net cash provided by
                       
operating activities:
                       
Silverhawk impairment loss
                91,025  
Regulatory disallowance
                138,562  
Depreciation and amortization including nuclear fuel
    403,896       386,760       381,604  
Deferred fuel and purchased power
    (196,136 )     (252,849 )     (172,756 )
Deferred fuel and purchased power amortization
    231,106       265,337        
Deferred fuel and purchased power disallowance
    14,370              
Allowance for equity funds used during construction
    (21,195 )     (14,312 )     (11,191 )
Deferred income taxes
    (58,027 )     27,738       (23,806 )
Change in mark-to-market valuations
    17,579       28,464       (11,670 )
Changes in current assets and liabilities:
                       
Customer and other receivables
    62,850       9,189       (38,763 )
Materials, supplies and fossil fuel
    (29,776 )     (9,094 )     (16,836 )
Other current assets
    (10,040 )     (890 )     (1,395 )
Accounts payable
    (42,004 )     (46,055 )     (6,392 )
Home inventory
    (56,883 )     11,563       (21,400 )
Accrued taxes
    20,764       (22,329 )     43,624  
Other current liabilities
    22,657       21,763       1,567  
Proceeds from the sale of real estate assets
    82,521       34,990       16,218  
Real estate investments
    (121,316 )     (126,229 )     (88,055 )
Change in margin and collateral accounts — assets
    (37,371 )     (249,792 )     251,925  
Change in margin and collateral accounts — liabilities
    19,284       (46,444 )     (17,012 )
Changes in unrecognized tax benefits
    25,178              
Change in other long-term assets
    (23,826 )     17,541       (35,793 )
Change in other long-term liabilities
    47,162       30,896       74,573  
 
                 
Net cash flow provided by operating activities
    657,936       393,502       730,296  
 
                 
 
                       
CASH FLOWS FROM INVESTING ACTIVITIES
                       
Capital expenditures
    (918,581 )     (737,779 )     (633,532 )
Capitalized interest
    (23,063 )     (20,990 )     (12,018 )
Purchase of Sundance Plant
                (185,046 )
Proceeds from the sale of Silverhawk
          207,620        
Purchases of investment securities
    (36,525 )     (1,439,404 )     (2,962,278 )
Proceeds from sale of investment securities
    69,225       1,406,704       3,143,481  
Proceeds from nuclear decommissioning trust sales
    259,026       254,651       186,215  
Investment in nuclear decommissioning trust
    (279,768 )     (275,393 )     (204,633 )
Proceeds from sale of real estate investments
    58,139       39,621       82,719  
Other
    (1,807 )     (3,763 )      
 
                 
Net cash flow used for investing activities
    (873,354 )     (568,733 )     (585,092 )
 
                 
 
                       
CASH FLOWS FROM FINANCING ACTIVITIES
                       
Issuance of long-term debt
    230,571       757,636       1,088,815  
Repayment of long-term debt
    (162,060 )     (527,864 )     (1,288,034 )
Short-term borrowings and payments — net
    304,911       9,911       (46,413 )
Dividends paid on common stock
    (210,473 )     (201,220 )     (186,677 )
Common stock equity issuance
    24,089       39,548       298,168  
Other
    (2,509 )     30,427       (20,426 )
 
                 
Net cash flow provided by (used for) financing activities
    184,529       108,438       (154,567 )
 
                 
 
NET DECREASE IN CASH AND CASH EQUIVALENTS
    (30,889 )     (66,793 )     (9,363 )
 
                       
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    87,210       154,003       163,366  
 
                 
 
                       
CASH AND CASH EQUIVALENTS AT END OF YEAR
  $ 56,321     $ 87,210     $ 154,003  
 
                 
Supplemental disclosure of cash flow information
                       
Cash paid during the period for:
                       
Income taxes paid, net of refunds
  $ 204,643     $ 157,245     $ 86,711  
Interest paid, net of amounts capitalized
  $ 193,533     $ 153,503     $ 181,975  
See Notes to Pinnacle West’s Consolidated Financial Statements.

66


 

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(dollars in thousands)
                         
    Year Ended December 31,  
    2007     2006     2005  
COMMON STOCK (Note 7)
                       
Balance at beginning of year
  $ 2,114,550     $ 2,067,377     $ 1,769,047  
Issuance of common stock
    24,089       39,420       298,330  
Other
    (2,852 )     7,753        
 
                 
Balance at end of year
    2,135,787       2,114,550       2,067,377  
 
                 
 
                       
TREASURY STOCK (Note 7)
                       
Balance at beginning of year
    (449 )     (1,245 )     (428 )
Purchase of treasury stock
    (1,964 )     (229 )     (1,601 )
Reissuance of treasury stock used for stock compensation, net
    359       1,025       784  
 
                 
Balance at end of year
    (2,054 )     (449 )     (1,245 )
 
                 
 
                       
RETAINED EARNINGS
                       
Balance at beginning of year
    1,319,747       1,193,712       1,204,122  
Net income
    307,143       327,255       176,267  
Common stock dividends
    (210,473 )     (201,220 )     (186,677 )
Cumulative effect of change in accounting for income taxes (Note 4)
    (2,676 )            
 
                 
Balance at end of year
    1,413,741       1,319,747       1,193,712  
 
                 
 
                       
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
                       
Balance at beginning of year
    12,268       165,120       (22,545 )
Pension and other postretirement benefits (Note 8):
                       
Unrealized actuarial loss, net of tax benefit of ($13,573)
    (21,976 )            
Prior service cost, net of tax benefit of ($495)
    (769 )            
Amortization to income:
                       
Actuarial loss, net of tax expense of $1,670
    2,214              
Prior service cost, net of tax expense of $252
    391              
Transition obligation, net of tax expense of $43
    67              
Minimum pension liability adjustment, net of tax expense (benefit) of $28,425 and ($9,526)
          44,086       (15,489 )
Adjustment to reflect a change in accounting, net of tax expense of $22,412
          33,928        
Derivative instruments:
                       
Net unrealized gain (loss), net of tax expense (benefit) of ($414), ($137,606) and $179,927
    (785 )     (214,777 )     281,019  
Reclassification of net realized gain to income, net of tax benefit of ($4,679), ($10,308) and ($50,056)
    (7,273 )     (16,089 )     (77,865 )
 
                 
Balance at end of year
    (15,863 )     12,268       165,120  
 
                 
 
                       
TOTAL COMMON STOCK EQUITY
  $ 3,531,611     $ 3,446,116     $ 3,424,964  
 
                 
 
                       
COMPREHENSIVE INCOME
                       
Net income
  $ 307,143     $ 327,255     $ 176,267  
Other comprehensive income (loss)
    (28,131 )     (186,780 )     187,665  
 
                 
Comprehensive income
  $ 279,012     $ 140,475     $ 363,932  
 
                 
See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Consolidation and Nature of Operations
     Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado, Pinnacle West Marketing & Trading, and Pinnacle West Energy (dissolved as of August 31, 2006). Significant intercompany accounts and transactions between the consolidated companies have been eliminated.
     APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all 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. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. APSES provides energy-related projects and competitive commodity energy to commercial and industrial retail customers in competitive markets in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in early 2007. These operations were previously conducted by a division of Pinnacle West through the end of 2006.
Accounting Records and Use of Estimates
     Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (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.
Derivative Accounting
     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 instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall 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 transactions.
     We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if certain hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). To the extent the amounts that would otherwise be recognized in income are eligible to be recovered through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. 
     Under fair value (mark-to-market) accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, as current or long-term assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets.
     We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted.
     When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers, which we convert into monthly prices using historical relationships.
     For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.
     For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.
     The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.
     The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.
     See Note 2 for information about a new accounting standard on fair value measurements.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     See Note 18 for additional information about our derivative and energy trading accounting policies.
Regulatory Accounting
     APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.
     Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
     A major component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery or refund 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates, subject to specified parameters.
     The detail of regulatory assets is as follows (dollars in millions):
                 
    December 31,  
    2007     2006  
Pension and other postretirement benefits
  $ 338     $ 473  
Deferred fuel and purchased power (a) (Note 3)
    111       160  
Regulatory asset for deferred income taxes
    40       27  
Deferred compensation
    30       28  
Competition rules compliance charge (a)
    25       34  
Loss on reacquired debt (b)
    16       17  
Deferred fuel and purchased power – mark-to-market
    7       62  
Other
    58       45  
 
           
Total regulatory assets (c)
  $ 625     $ 846  
 
           
 
(a)   Subject to a carrying charge.
 
(b)   See “Reacquired Debt Costs” below.
 
(c)   There are no regulatory assets for which regulators have allowed recovery of costs but not allowed a return by exclusion from rate base.
     The detail of regulatory liabilities is as follows (dollars in millions):

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                 
    December 31,  
    2007     2006  
Removal costs (a)
  $ 392     $ 387  
Regulatory liability related to asset retirement obligations
    153       133  
Tax benefit of Medicare subsidy
    35       50  
Deferred gains on utility property
    20       20  
Deferred interest income (b)
    13       18  
Regulatory liability for deferred income taxes
    6       11  
Other
    24       16  
 
           
Total regulatory liabilities
  $ 643     $ 635  
 
           
 
(a)   In accordance with SFAS No. 71, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
 
(b)   Subject to a carrying charge.
Utility Plant and Depreciation
     Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:
    material and labor;
 
    contractor costs;
 
    capitalized leases;
 
    construction overhead costs (where applicable); and
 
    capitalized interest or an allowance for funds used during construction.
     We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.
     APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated under SFAS No. 143 “Accounting for Asset Obligations,” as interpreted by FIN 47. APS believes it can recover in regulated rates the costs calculated in accordance with SFAS No. 143.
     We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2007 were as follows:

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
    Fossil plant – 17 years;
 
    Nuclear plant – 17 years;
 
    Other generation – 29 years;
 
    Transmission – 43 years;
 
    Distribution – 33 years; and
 
    Other – 6 years.
     For the years 2005 through 2007, the depreciation rates ranged from a low of 1.11% to a high of 12.46%. The weighted-average rate was 3.11% for 2007, 3.14 % for 2006 and 3.0% for 2005. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years.
Investments
     El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).
     Our investments in the nuclear decommissioning trust fund are accounted for in accordance with EITF 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” See Note 12 for more information on these investments.
Capitalized Interest
     Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. The rate used to calculate capitalized interest was a composite rate of 5.8% for 2007, 6.8% for 2006 and 5.7% for 2005. Capitalized interest ceases when construction is complete.
Allowance for Funds Used During Construction
     AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. APS’ allowance for borrowed funds is included in capitalized interest on the Consolidated Financial Statements. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
     AFUDC was calculated by using a composite rate of 8.2% for 2007, 8.0% for 2006 and 7.7% for 2005. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Electric Revenues
     We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Beginning April 2005, in accordance with a 2005 ACC order, we also exclude city franchise fees from both electric revenues and operating expenses.
     Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and purchased power and fuel costs.
     All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis.
Real Estate Revenues
     SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed under the percentage of completion method per SFAS No. 66, “Accounting for Sales of Real Estate.” SunCor recognizes income only after the asset title has passed. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. In addition, see Note 22 – Discontinued Operations.
Real Estate Investments
     Real estate investments primarily include SunCor’s land, home inventory, commercial property and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except that, to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Homes under construction classified as “real estate investments” on the Consolidated Balance Sheets are transferred to “home inventory” upon completion of construction with the expectation that they will be sold in a timely manner. In previous years, “home inventory” was classified as “other current assets” on the Consolidated Balance Sheets. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. In addition, see Note 22 – Discontinued Operations.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash and Cash Equivalents
     We consider all highly liquid investments with a maturity of three months or less at acquisition to be cash equivalents.
     Investments in auction rate securities have interest rates that are reset on a short-term basis; however, the underlying contract maturity dates extend beyond three months. We classify the investments in auction rate securities as investment in debt securities on our Consolidated Balance Sheets.
Nuclear Fuel
     APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
     APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal and Note 12 for information on nuclear decommissioning costs.
Income Taxes
     Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes” and FIN 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the most probable resolution of all known and measurable tax exposures. See Note 4.
Reacquired Debt Costs
     APS defers gains and losses incurred upon early retirement of debt. These costs are amortized equally on a monthly basis over the remaining life of the original debt consistent with its ratemaking treatment.
Stock-based Compensation
     Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and some of our subsidiaries. Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective application method. Because the fair value recognition provisions of both SFAS No. 123 and SFAS No. 123(R) are materially

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
consistent with respect to our stock-based compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements. See Note 16.
Intangible Assets
     We have no goodwill recorded and have separately disclosed other intangible assets, primarily software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. Amortization expense was $37 million in 2007, $39 million in 2006 and $33 million in 2005. Estimated amortization expense on existing intangible assets over the next five years is $29 million in 2008, $20 million in 2009, $19 million in 2010, $12 million in 2011 and $10 million in 2012. At December 31, 2007, the weighted average remaining amortization period for intangible assets was 5 years.
2. 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 but do not expect it to have a material impact on our financial statements.
     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 but do not expect it to have a material impact on our financial statements.
     See Notes 18 and S-3 for a discussion of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), which we adopted January 1, 2008.
     See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007.
3. Regulatory Matters
     Retail Rate Order
     Retail Rate Increase On June 28, 2007, the ACC issued an order (the “Retail Rate Order”) in a general retail rate case that APS filed in late 2005. The Retail Rate Order approved a $322 million increase in APS’ annual retail base revenues, effective July 1, 2007, which included a $315 million fuel-related increase and a $7 million non-fuel related increase. The Retail Rate Order also authorized APS’ recovery of approximately $34 million of 2005 Deferrals through a temporary PSA surcharge over a twelve-month period beginning July 1, 2007. The ACC disallowed approximately $14 million of 2005 Deferrals because it found the Palo Verde outage costs giving rise to those amounts resulted from APS’ imprudence.
     PSA Modifications The Retail Rate Order modified the PSA in various respects, effective July 1, 2007. The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case,

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. As modified by the Retail Rate Order, the PSA 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 Rate (currently $0.0325 per kWh);
 
    under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchase power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate;
 
    an adjustment is made annually each February 1st and goes into effect automatically unless suspended by the ACC;
 
    the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which will be reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
 
    the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) an “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component;
 
    amounts to be recovered or refunded through the sum of the PSA components discussed in the preceding bullet point are limited to a maximum plus or minus $0.004 per kWh change in the PSA rate in any PSA Year; and
 
    the PSA adjustor that took effect on February 1, 2007 ($0.004 per kWh), and that was scheduled to expire on January 31, 2008, will remain in effect as long as necessary after January 31, 2008 to collect $46 million of 2007 fuel and purchased power costs deferred as a result of the mid-2007 implementation of the new Base Fuel Rate.
     PSA Balance
     The following table shows the changes in the deferred fuel and purchased power regulatory asset for the years ended December 31, 2007 and 2006 (dollars in millions):

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                 
    2007     2006  
Beginning balance
  $ 160     $ 173  
Deferred fuel and purchased power costs-current period
    189       244  
Regulatory disallowance
    (14 )      
Interest on deferred fuel and purchased power
    7       8  
Amounts recovered through revenues
    (231 )     (265 )
 
           
Ending balance
  $ 111     $ 160  
 
           
     The PSA rate for the PSA Year beginning February 1, 2008 was set at the maximum $0.004 per kWh.  Any uncollected deferrals during the 2008 PSA Year resulting from this limit will be included in the Historical Component of the PSA rate for the PSA Year beginning February 1, 2009.
     2006 Deferrals
     In May 2006, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde outage costs. APS recorded approximately $79 million of 2006 Deferrals, virtually all of which were associated with a Unit 1 vibration issue. On October 4, 2007, the ACC staff filed a report with the ACC that concluded that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that these costs, which have been fully recovered, were prudently incurred.
     Line Extension Schedule
     The Retail Rate Order required APS to file a revised line extension schedule for ACC approval that would eliminate certain footage and equipment allowances for new or expanded electric service and remove any requirement for economic feasibility analyses used to determine whether or how much of an allowance should be granted. These changes would permit APS to collect, on a current basis, costs related to line extensions.
     On October 24, 2007, APS filed a proposed amendment to its line extension schedule, including a proposal to treat line extension payments received as non-refundable other electric revenues. APS proposed to “grandfather” applicants that have executed line extension agreements prior to the effective date of its amended line extension schedule. The ACC Staff issued a recommended order that was consistent with APS’ proposed line extension amendments in all significant respects except for the authorized accounting treatment. The ACC staff proposed that payments received for new or upgraded service be treated as contributions in aid of construction (“CIAC”), rather than as non-refundable other electric revenues as APS requested. CIAC treatment would result in a positive cash flow that will partially offset capital expenditures, but without any revenue impact. On February 13, 2008, the ACC voted to approve the ACC staff recommended order, with minor modifications.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     Rate Requests for Transmission and Ancillary Services
     On July 10, 2007, APS submitted a revised Open Access Transmission Tariff filing with the FERC to move from a fixed rate to a formula rate in order to more accurately reflect the costs that APS incurs in providing transmission and ancillary services. The requested formula rate would have resulted in an estimated $37 million increase in annual transmission revenues, effective October 1, 2007. The proposed formula rate would be updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and projected capital expenditures. Approximately $30 million of the requested increase represents charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”).
     On September 21, 2007, the FERC issued an order on these proposed revisions to APS’ transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge procedures, which are underway. The proposed rates become effective March 1, 2008, subject to refund based upon the ultimate outcome of proceedings at the FERC on this matter.
     On December 31, 2007, APS filed with the ACC an application to increase annual pretax retail revenues by approximately $30 million, effective March 1, 2008, to cover the Retail Transmission Charges authorized by the FERC. This retail rate increase implements an ACC-approved mechanism by which changes in Retail Transmission Charges can be reflected in APS’ retail rates. On February 13, 2008, the ACC voted to approve APS’ request, subject to refund pending final outcome of FERC proceedings on this matter.
     Other
     On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003. As part of this order, APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was $139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $84 million in 2005.
Federal
     FERC Order
     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (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’ authority to make sales at market-based rates in the APS control area (the “April 17 Order”). The

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
     On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on October 12, 2007. This compliance filing was conditionally accepted by FERC in an order issued January 17, 2008, requiring an additional compliance filing by the Pinnacle West Companies by February 19, 2008.
     Based upon an analysis of this matter and preliminary calculations of the refund obligations, at this time neither Pinnacle West nor APS believes that this proceeding will have a material adverse effect on its financial position, results of operations or cash flows.
4. Income Taxes
     Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.
     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 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. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next six months, we expect that the IRS will finalize its examination of the 2001 return, which will include a settlement on the tax accounting method change. Although the ultimate outcome of this matter cannot currently be predicted, the current status of the examination has resulted in changes in our judgment, which are reflected in the reconciliation of the total amounts of unrecognized tax benefits presented below. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows. We do not expect that there will be any other significant increases or decreases in our unrecognized tax benefits within the next 12 months.
     We adopted FIN 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

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
     Following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Consolidated Balance Sheets (dollars in thousands):
         
Total unrecognized tax benefits, January 1, 2007
  $ 132,691  
Additions for tax positions of the current year
     
Additions for tax positions of prior years
    65,022  
Reductions for tax positions of prior years for:
       
Changes in judgment
    (37,419 )
Settlements with taxing authorities
    (2,425 )
Lapses of applicable statute of limitations
     
 
     
Total unrecognized tax benefits, December 31, 2007
  $ 157,869  
 
     
     Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately $5 million of tax positions that, if recognized, would decrease our effective tax rate.
     We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of operations as income tax expense. For 2007, the amount of interest recognized in the statement of operations related to unrecognized tax benefits was $3 million.
     As of December 31, 2007, the total amount of interest expense recognized in the statement of financial position related to unrecognized tax benefits was $57 million. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, we have recognized $5 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.
     As of December 31, 2007, the tax year ended December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ended prior to December 31, 1999 may remain subject to examination by state taxing authorities.
     The components of income tax expense are as follows (dollars in thousands):

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         
    Year Ended December 31,  
    2007     2006     2005  
Current:
                       
Federal
  $ 183,547     $ 110,029     $ 107,837  
State
    30,972       21,507       13,064  
 
                 
Total current
    214,519       131,536       120,901  
 
                 
Deferred:
                       
Income from continuing operations
    (56,147 )     31,452       11,930  
Discontinued operations
    (1,880 )           (35,736 )
 
                 
Total deferred
    (58,027 )     31,452       (23,806 )
 
                 
Total income tax expense
    156,492       162,988       97,095  
Less: income tax expense (benefit) on discontinued operations
    4,045       6,570       (29,797 )
 
                 
Income tax expense — continuing operations
  $ 152,447     $ 156,418     $ 126,892  
 
                 
     The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):
                         
    Year Ended December 31,  
    2007     2006     2005  
Federal income tax expense at 35% statutory rate
  $ 158,753     $ 165,746     $ 122,519  
Increases (reductions) in tax expense resulting from:
                       
State income tax net of federal income tax benefit
    16,964       17,309       11,981  
Credits and favorable adjustments related to prior years resolved in current year
    (13,205 )     (14,028 )      
Medicare Subsidy Part-D
    (3,236 )     (3,156 )     (2,733 )
Allowance for equity funds used during construction (see Note 1)
    (6,899 )     (4,679 )     (3,694 )
Other
    70       (4,774 )     (1,181 )
 
                 
Income tax expense — continuing operations
  $ 152,447     $ 156,418     $ 126,892  
 
                 
     The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
                 
    December 31,  
    2007     2006  
Current asset
  $ 31,510     $ 982  
Long-term liability
    (1,243,743 )     (1,225,798 )
 
           
Accumulated deferred income taxes — net
  $ (1,212,233 )   $ (1,224,816 )
 
           

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The components of the net deferred income tax liability were as follows (dollars in thousands):
                 
    December 31,  
    2007     2006  
DEFERRED TAX ASSETS
               
Risk management and trading activities
  $ 13,958     $ 66,946  
Regulatory liabilities:
               
Asset retirement obligation
    214,607       203,846  
Federal excess deferred income taxes
    11,091       12,714  
Tax benefit of Medicare subsidy
    11,727       18,214  
Other
    26,579       27,283  
Pension and other postretirement liabilities
    211,192       272,484  
Deferred gain on Palo Verde Unit 2 sale leaseback
    14,408       16,160  
Other
    112,209       73,811  
 
           
Total deferred tax assets
    615,771       691,458  
 
           
DEFERRED TAX LIABILITIES
               
Plant-related
    (1,538,183 )     (1,509,812 )
Risk management and trading activities
    (29,531 )     (72,755 )
Regulatory assets:
               
Deferred fuel and purchased power
    (43,661 )     (62,889 )
Deferred fuel and purchased power — mark-to-market
    (2,782 )     (24,427 )
Pension and other postretirement benefits
    (133,120 )     (185,602 )
Other
    (80,727 )     (60,789 )
 
           
Total deferred tax liabilities
    (1,828,004 )     (1,916,274 )
 
           
Accumulated deferred income taxes — net
  $ (1,212,233 )   $ (1,224,816 )
 
           
5. Lines of Credit and Short-Term Borrowings
     Pinnacle West had a committed line of credit with various banks totaling $300 million at December 31, 2007 and December 31, 2006, which was available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuance of letters of credit. The current line terminates in December 2010. Pinnacle West had no outstanding borrowings under the lines of credit at December 31, 2007 and December 31, 2006. Pinnacle West had approximately $5 million of letters of credit issued under the line at December 31, 2007 and approximately $4 million of letters of credit issued under the line at December 31, 2006. The commitment fees were 0.15% in 2007 and 2006. Pinnacle West had commercial paper borrowings of $115 million outstanding at December 31, 2007 and $28 million outstanding at December 31, 2006. The weighted average interest rates were 5.73% at December 31, 2007 and 5.625% at December 31, 2006. All Pinnacle West and APS bank lines of credit and commercial paper agreements are unsecured.
     APS had two committed lines of credit with various banks totaling $900 million at December 2007 and 2006, all of which were available either to support the issuance of up to $250 million in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
commercial paper or to be used for bank borrowings, including the issuance of letters of credit. The $400 million line terminates in December 2010 and the $500 million line terminates in September 2011. APS may increase the $500 million line to $600 million if certain conditions are met. The commitment fees for these lines of credit were 0.10% and 0.11% at December 31, 2007 and December 31, 2006. APS had bank borrowings outstanding of $218 million under the $500 million line of credit at December 31, 2007 and no borrowings outstanding at December 31, 2006. The weighted average interest rate was 5.361% at December 31, 2007. APS had approximately $4 million of letters of credit issued under the $400 million line at December 31, 2007 and 2006.
     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 October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.
     SunCor had two revolving lines of credit totaling $170 million at December 31, 2007, and December 31, 2006 maturing in October 2008 and December 2008. The commitment fees were 0.125% in 2007 and 2006 for the $150 million line of credit. The commitment fees for the $20 million line of credit were 0.50% in 2007 and 2006. SunCor had $94 million outstanding at December 31, 2007 and $118 million outstanding at December 31, 2006. The weighted-average interest rate was 7.27% at December 31, 2007 and 7.09% at December 31, 2006. Interest was based on LIBOR plus 2.0% for 2007 and 2006. The balance is included in current maturities of long-term debt on the Consolidated Balance Sheets at December 31, 2007 and 2006. SunCor had other short-term loans in the amount of $8 million at December 31, 2007 and $8 million at December 31, 2006. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2007 and 2006.
6. Long-Term Debt
     Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2007 and 2006 (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                             
    Maturity   Interest     December 31,  
    Dates (a)   Rates     2007     2006  
APS
                           
 
                           
Pollution control bonds
  2024-2034     (b )   $ 565,855     $ 565,855  
Pollution control bonds with senior notes
  2029     5.05 %     90,000       90,000  
Unsecured notes
  2011     6.375 %     400,000       400,000  
Unsecured notes
  2012     6.50 %     375,000       375,000  
Unsecured notes
  2033     5.625 %     200,000       200,000  
Unsecured notes
  2015     4.650 %     300,000       300,000  
Unsecured notes
  2014     5.80 %     300,000       300,000  
Secured note
  2014     6.00 %     1,430       1,592  
Senior notes
  2035     5.50 %     250,000       250,000  
Senior notes (c)
  2016     6.25 %     250,000       250,000  
Senior notes (c)
  2036     6.875 %     150,000       150,000  
Unamortized discount and premium
                (8,883 )     (9,857 )
Capitalized lease obligations
  2007-2012     (d )     4,457       5,880  
 
                       
Subtotal (e)
                2,877,859       2,878,470  
 
                       
SUNCOR
                           
Notes payable
  2008-2013     (f )     237,671       180,316  
Capitalized lease obligations
  2007-2010     (g )     368       328  
 
                       
Subtotal
                238,039       180,644  
 
                       
PINNACLE WEST
                           
Senior notes (h)
  2011     5.91 %     175,000       175,000  
Capitalized lease obligations
  2007     5.45 %           115  
 
                       
Subtotal
                175,000       175,115  
 
                       
Total long-term debt
                3,290,898       3,234,229  
Less current maturities
                163,773       1,596  
 
                       
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
              $ 3,127,125     $ 3,232,633  
 
                       
 
(a)   This schedule does not reflect the timing of redemptions that may occur prior to maturity.
 
(b)   The weighted-average rate was 3.76% at December 31, 2007 and 3.77% at December 31, 2006. Changes in short-term interest rates would affect the costs associated with this debt. In addition, these amounts include $343 million of auction rate debt securities backed by insurance at December 31, 2007 and 2006.
 
(c)   On August 3, 2006, APS issued $250 million 6.25% notes due 2016 and $150 million 6.875% notes due 2036. A portion of the proceeds was used to repay outstanding commercial paper balances and $84 million of its 6.75% senior note that matured November 15, 2006. The remainder has been used to fund its construction program and other general corporate purposes.
 
(d)   The weighted-average interest rate was 5.51% at December 31, 2007 and 6.20% at December 31, 2006.
 
(e)   APS’ long-term debt less current maturities was $2.877 billion at December 31, 2007 and $2.878 billion at December 31, 2006. APS’ current maturities of long-term debt were $1 million at December 31, 2007 and 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
(f)   SunCor had $94 million outstanding at December 31, 2007 under its revolving lines of credit. The weighted-average interest rate was 7.27% at December 31, 2007. The remaining amount of approximately $143 million at December 31, 2007 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 1.7%, 2.0% and 2.25%. SunCor had $118 million outstanding at December 31, 2006 under its revolving line of credit. The weighted-average interest rate was 7.08% at December 31, 2006. The remaining amount of approximately $62 million at December 31, 2006 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 2.25%. There is also a note at a fixed rate of 4.25% at December 31, 2007 and 2006
 
(g)   The weighted-average interest rate was 7.0% at December 31, 2007 and 6.25% at December 31, 2006.
 
(h)   On February 28, 2006, Pinnacle West entered into a $200 million Senior Notes Uncommitted Master Shelf Agreement with Prudential Investment Management Inc. (“Prudential”). Under the terms of the agreement, Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential at any time prior to December 31, 2007. The maturity of the notes cannot exceed five years. On February 28, 2006, Pinnacle West issued $175 million of its 5.91% senior notes, series A, to Prudential.
     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 cannot exceed 65%. At December 31, 2007, the ratio was approximately 50% 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 approximately 4.7 times under APS’ bank financing agreements as of December 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, our bank financing agreements contain a pricing grid in which interest costs we pay are determined by our current credit ratings.
     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.
     An existing ACC order requires APS to maintain a common equity ratio of at least 40%. 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 December 31, 2007, APS’ common equity ratio, as defined, was 54%, its total common equity was approximately $3.4

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
billion, and total capitalization was approximately $6.2 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.5 billion, assuming APS’ total capitalization remains the same.
     SunCor has a $150 million loan facility secured primarily by an interest in land, commercial properties, land contracts and homes under construction. The loan facility requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. As of December 31, 2007, the amount of SunCor’s net assets that could not be transferred to Pinnacle West in the form of cash dividends as a result of these covenants was approximately $217 million.
     As a result of the restrictions in the preceding two paragraphs, as of December 31, 2007, the restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at December 31, 2007, our consolidated net assets were approximately $3.5 billion). These restrictions do not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions):
                 
Year   Pinnacle West     APS  
2008
  $ 164     $ 1  
2009
    72       1  
2010
    224       224  
2011
    578       401  
2012
    376       376  
Thereafter
    1,886       1,884  
 
           
Total
  $ 3,300     $ 2,887  
 
           
7. Common Stock and Treasury Stock
     Our common stock and treasury stock activity during each of the three years 2007, 2006 and 2005 is as follows (dollars in thousands):

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                 
    Common Stock     Treasury Stock  
    Shares     Amount     Shares     Amount  
Balance at December 31, 2004
    91,802,861     $ 1,769,047       (9,522 )   $ (428 )
Common stock issuance (a)
    7,274,272       298,330              
Purchase of treasury stock (b)
                (28,124 )     (1,601 )
Reissuance of treasury stock for stock compensation (net)
                17,588       784  
 
                       
Balance at December 31, 2005
    99,077,133       2,067,377       (20,058 )     (1,245 )
 
Common stock issuance
    883,933       39,420              
Purchase of treasury stock (b)
                (5,505 )     (229 )
Reissuance of treasury stock for stock compensation (net)
                23,144       1,025  
Other
          7,753              
 
                       
Balance at December 31, 2006
    99,961,066       2,114,550       (2,419 )     (449 )
 
                               
Common stock issuance
    564,404       24,089              
Purchase of treasury stock (b)
                (47,218 )     (1,964 )
Reissuance of treasury stock for stock compensation (net)
                10,132       359  
Other
          (2,852 )            
 
                       
Balance at December 31, 2007
    100,525,470     $ 2,135,787       (39,505 )   $ (2,054 )
 
                       
 
(a)   On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the net proceeds for general corporate purposes, including making capital contributions to APS, which, in turn, used such funds to pay a portion of the approximately $190 million purchase price to acquire the Sundance Plant and for other capital expenditures incurred to meet the growing needs of APS’ service territory.
 
(b)   Represents shares of common stock withheld from certain stock awards for tax purposes.
8. Retirement Plans and Other Benefits
     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 its subsidiaries. All new employees participate in the account balance plan. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.
     We also sponsor other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.
     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 fair market value of investments in our retirement and postretirement plans is determined using actively-quoted prices when available. When actively-quoted prices are not available, we use prices provided by external sources, models or other valuation methods. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through the application of these methods.
     A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans are attributable to APS and therefore are recoverable in rates. Accordingly these changes are recorded as a regulatory asset.
     The following table provides details of the plans’ benefit costs. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants (dollars in thousands):
                                                 
    Pension     Other Benefits  
    2007     2006     2005     2007     2006     2005  
Service cost-benefits earned during the period
  $ 51,803     $ 47,287     $ 45,027     $ 18,491     $ 19,968     $ 20,913  
Interest cost on benefit obligation
    100,736       92,196       87,189       35,284       34,653       34,223  
Expected return on plan assets
    (107,165 )     (95,912 )     (88,403 )     (42,177 )     (36,930 )     (30,471 )
Amortization of:
                                               
Transition (asset) obligation
          (645 )     (3,227 )     3,005       3,005       3,005  
Prior service cost (credit)
    2,957       2,401       2,401       (125 )     (125 )     (125 )
Net actuarial loss
    16,331       23,366       19,810       3,929       8,662       9,243  
 
                                   
Net periodic benefit cost
  $ 64,662     $ 68,693     $ 62,797     $ 18,407     $ 29,233     $ 36,788  
 
                                   
Portion of cost charged to expense
  $ 28,063     $ 30,912     $ 26,375     $ 7,989     $ 13,155     $ 15,451  
 
                                   
APS share of costs charged to expense
  $ 26,548     $ 29,203     $ 24,169     $ 7,557     $ 12,428     $ 14,159  
 
                                   

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The following table shows the plans’ changes in the benefit obligations and funded status for the years 2007 and 2006 (dollars in thousands):
                                 
    Pension     Other Benefits  
    2007     2006     2007     2006  
Change in Benefit Obligation
                               
Benefit obligation at January 1
  $ 1,670,274     $ 1,596,068     $ 616,985     $ 585,678  
Service cost
    51,803       47,287       18,491       19,968  
Interest cost
    100,736       92,196       35,284       34,653  
Benefit payments
    (52,168 )     (49,189 )     (17,763 )     (16,439 )
Actuarial gains
    (52,227 )     (19,588 )     (47,872 )     (6,875 )
Plan amendments
    2,426       3,500              
 
                       
Benefit obligation at December 31
    1,720,844       1,670,274       605,125       616,985  
 
                       
 
                               
Change in Plan Assets
                               
Fair value of plan assets at January 1
  $ 1,214,229     $ 1,064,848     $ 480,638     $ 416,174  
Actual return on plan assets
    101,138       148,895       26,952       47,988  
Employer contributions
    52,000       46,500       18,407       29,233  
Benefit payments
    (48,428 )     (46,014 )     (26,233 )     (12,757 )
 
                       
Fair value of plan assets at December 31
    1,318,939       1,214,229       499,764       480,638  
 
                       
Funded Status at December 31
  $ (401,905 )   $ (456,045 )   $ (105,361 )   $ (136,347 )
 
                       
     The following table shows the projected benefit obligation and the accumulated benefit obligation for the pension plan in excess of plan assets as of December 31, 2007 and 2006 (dollars in thousands):
                 
    2007   2006
Projected benefit obligation
  $ 1,720,844     $ 1,670,274  
Accumulated benefit obligation
    1,484,444       1,426,492  
Fair value of plan assets
    1,318,939       1,214,229  
     The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2007 and 2006 (dollars in thousands):
                                 
    Pension     Other Benefits  
    2007     2006     2007     2006  
Current asset
  $     $     $ 1,321     $  
Current liability
    (3,984 )     (3,540 )            
Noncurrent liability
    (397,921 )     (452,505 )     (106,682 )     (136,347 )
 
                       
Net amount recognized
  $ (401,905 )   $ (456,045 )   $ (105,361 )   $ (136,347 )
 
                       

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The following table shows the details related to accumulated other comprehensive loss before income taxes as of December 31, 2007 and 2006 (dollars in thousands):
                                 
    Pension     Other Benefits  
    2007     2006     2007     2006  
Net actuarial loss
  $ 268,532     $ 331,054     $ 106,407     $ 143,079  
Prior service cost (credit)
    12,401       12,932       (1,045 )     (1,171 )
Transition obligation
                15,024       18,029  
APS’ portion recorded as a regulatory asset
    (221,787 )     (318,461 )     (116,425 )     (154,531 )
 
                       
Accumulated other comprehensive loss
  $ 59,146     $ 25,525     $ 3,961     $ 5,406  
 
                       
     The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2008 (dollars in thousands):
                 
    Pension     Other Benefits  
Net actuarial loss
  $ 9,048     $ 4,042  
Prior service cost (credit)
    2,455       (125 )
Transition obligation
          3,005  
 
           
Total amounts estimated to be amortized from accumulated other comprehensive income and regulatory assets in 2008
  $ 11,503     $ 6,922  
 
           
     The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
                                 
                    Benefit Costs
    Benefit Obligations   For the Years Ended
    As of December 31,   December 31,
    2007   2006   2007   2006
Discount rate-pension
    6.25 %     5.90 %     5.90 %     5.66 %
Discount rate-other benefits
    6.31 %     5.93 %     5.93 %     5.68 %
Rate of compensation increase
    4.00 %     4.00 %     4.00 %     4.00 %
Expected long-term return on plan assets
    N/A       N/A       9.00 %     9.00 %
Initial health care cost trend rate
    8.00 %     8.00 %     8.00 %     8.00 %
Ultimate health care cost trend rate
    5.00 %     5.00 %     5.00 %     5.00 %
Year ultimate health care trend rate is reached
    2012       2011       2011       2010  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2008, we are assuming a 9% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
     Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):
                 
    1% Increase   1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants
  $ 7     $ (5 )
Effect on service and interest cost components of net periodic other postretirement benefit costs
    10       (8 )
Effect on the accumulated other postretirement benefit obligation
    94       (76 )
Plan Assets
     Pinnacle West’s qualified pension plan and other postretirement benefit plans’ asset allocation at December 31, 2007 and 2006 is as follows:
                                                 
    Pension   Other Benefits
    2007   2006   Target   2007   2006   Target
Asset Category:
                                               
Equity securities
    68 %     69 %     68 %     70 %     74 %     70 %
Fixed income
    25       25       25       28       25       27  
Other
    7       6       7       2       1       3  
 
                                               
Total
    100 %     100 %     100 %     100 %     100 %     100 %
 
                                               
     The Board of Directors has delegated oversight of the plan assets to an Investment Management Committee. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with acceptable levels of risk. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West securities, and external management of plan assets.
     The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the other postretirement benefit plans. The investment policy for other postretirement benefit plans’ assets is similar to that of the pension plan assets described above.
Contributions
     The contribution to our pension plan in 2008 is estimated to be approximately $50 million. The contribution to our other postretirement benefit plans in 2008 is estimated to be approximately

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$20 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.
Estimated Future Benefit Payments
     Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):
                 
Year   Pension     Other Benefits (a)  
2008
  $ 60,536     $ 19,315  
2009
    66,799       21,246  
2010
    73,624       23,846  
2011
    82,764       26,579  
2012
    93,371       29,293  
 
           
Years 2013-2017
    639,326       194,680  
 
           
 
(a)   The expected future other benefit payments take into account the Medicare Part D subsidy.
Employee Savings Plan Benefits
     Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2007, costs related to APS’ employees represented 97% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. At December 31, 2007, approximately 15% of total plan assets were in Pinnacle West stock. Pinnacle West recorded expenses for this plan of approximately $7 million for 2007, $6 million for 2006 and $6 million for 2005. APS recorded expenses for this plan of approximately $6 million in 2007, $6 million in 2006 and $6 million in 2005.
9. Leases
     In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases and to purchase the property for fair market value at the end of the lease terms. Rent expense is calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the VIE’s involved in the Palo Verde sale leaseback transactions.
     In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.

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     Total lease expense recognized in the Consolidated Statements of Income was $73 million in 2007, $72 million in 2006 and $71 million in 2005. APS’ lease expense was $66 million in 2007, $64 million in 2006 and $58 million in 2005.
     The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2008 to 2015.
     Estimated future minimum lease payments for Pinnacle West’s and APS’ operating leases, excluding purchase power agreements, are approximately as follows (dollars in millions):
                 
    Pinnacle West        
Year   Consolidated     APS  
2008
  $ 79     $ 72  
2009
    75       69  
2010
    73       67  
2011
    68       63  
2012
    65       61  
Thereafter
    195       177  
 
           
Total future lease commitments
  $ 555     $ 509  
 
           
10. Jointly-Owned Facilities
     APS shares ownership of some of its generating and transmission facilities with other companies. Our share of operations and maintenance expense and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2007 (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                 
                            Construction
    Percent   Plant in   Accumulated   Work in
    Owned   Service   Depreciation   Progress
Generating facilities:
                               
Palo Verde Units 1 and 3
    29.1 %   $ 1,939,389     $ 1,038,432     $ 132,618  
Palo Verde Unit 2 (see Note 9)
    17.0 %     672,564       303,638       16,630  
Four Corners Units 4 and 5
    15.0 %     182,052       99,127       12,345  
Navajo Generating Station Units 1, 2 and 3
    14.0 %     255,592       142,144       1,855  
Cholla common facilities (a)
    63.9 %(b)     91,636       49,741       31,692  
Transmission facilities:
                               
ANPP 500KV System
    35.8 %(b)     79,515       24,001       4,399  
Navajo Southern System
    31.4 %(b)     38,935       12,665       5,575  
Palo Verde — Yuma 500KV System
    23.9 %(b)     9,230       3,857       3,427  
Four Corners Switchyards
    27.5 %(b)     3,198       1,304        
Phoenix — Mead System
    17.1 %(b)     36,032       4,823        
Palo Verde — Estrella 500KV System
    55.5 %(b)     74,318       3,990        
Harquahala
    80.0 %(b)                 6,418  
 
(a)   PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
 
(b)   Weighted average of interests.
11. 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 2007 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 December 31, 2007, APS had a regulatory liability of $11 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     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.
     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 $21.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
Fuel and Purchased Power Commitments
     Pinnacle West and APS are parties to various fuel and purchased power contracts with terms expiring between 2008 and 2025 that include required purchase provisions. Pinnacle West estimates the contract requirements to be approximately $418 million in 2008; $358 million in 2009; $293 million in 2010; $218 million in 2011; $216 million in 2012; and $1.6 billion thereafter. APS estimates the contract requirements to be approximately $375 million in 2008; $358 million in 2009; $293 million in 2010; $212 million in 2011; $210 million in 2012; and $1.6 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
     Of the various fuel and purchased power contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024.
     The following table summarizes our actual and estimated take-or-pay commitments (dollars in millions):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                                                         
    Actual   Estimated (a)
    2005   2006   2007   2008   2009   2010   2011   2012   Thereafter
Coal take-or-pay commitments
  $ 48     $ 67     $ 70     $ 81     $ 97     $ 75     $ 77     $ 78     $ 476  
 
(a)   Total take-or-pay commitments are approximately $884 million. The total net present value of these commitments is approximately $588 million.
Coal Mine Reclamation Obligations
     APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation was approximately $91 million at December 31, 2007 and $75 million at December 31, 2006 and is included in Deferred Credits and Other on the Consolidated Balance Sheets.
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. Several parties sought rehearing of this decision at the Ninth Circuit. 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 the FERC will have no material adverse impact on our financial position, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     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 December 28, 2006, certain parties petitioned the Supreme Court for a writ of certiorari. This petition was denied on June 18, 2007. The Ninth Circuit issued the mandate for this proceeding on December 4, 2007. The outcome of the further proceedings cannot be predicted at this time.
     On July 25, 2001, 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 was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Petitions for rehearing of this opinion were filed on December 17, 2007. Although the FERC ruling in this matter is being appealed and the FERC has not yet calculated the specific refund amounts at issue, we do not expect that the resolution of these issues 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.
Navajo Nation Litigation
     In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. 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, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.
Salt River Project
     Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserts that certain of these failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims that APS owes it approximately $29 million. APS disputes that it is required to pay these amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect that resolution of this matter will have a material adverse impact on our financial position, results of operations, or cash flows.
Litigation
     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.
12. Asset Retirement Obligations
     APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations

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primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term.
     Some of APS’ transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.
     Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites. The generation sites are strategically located to serve APS Native Load customers. Management expects to continuously use the sites and, thus, cannot estimate a potential closure date. The asset retirement obligations associated with our non-regulated assets are immaterial.
     The following schedule shows the change in our asset retirement obligations for 2007 and 2006 (dollars in millions):
                 
    2007     2006  
Asset retirement obligations at the beginning of year
  $ 268     $ 269  
Changes attributable to:
               
Liabilities settled
    (2 )     (2 )
Accretion expense
    20       19  
Estimated cash flow revisions
    (4 )     (18 )
 
           
Asset retirement obligations at the end of year
  $ 282     $ 268  
 
           
     In accordance with SFAS No. 71, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 1.
     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 securities and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our 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, we have recorded the offsetting amount of gains on investment securities in other regulatory liabilities or assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at December 31, 2007 and December 31, 2006 (dollars in millions):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                 
            Total  
            Unrealized  
    Fair Value     Gains  
2007
               
Equity securities
  $ 175     $ 68  
Fixed income securities
    204       5  
 
           
Total
  $ 379     $ 73  
 
           
 
               
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):
                         
    Year Ended December 31,
    2007   2006   2005
Realized gains
  $ 3     $ 9     $ 6  
Realized losses
    (4 )           (6 )
Proceeds from the sale of securities
    259       255       186  
     The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2007 is as follows (dollars in millions):
         
    Fair Value  
Less than one year
  $ 10  
1 year - 5 years
    42  
5 years - 10 years
    38  
Greater than 10 years
    114  
 
     
Total
  $ 204  
 
     
13. Selected Quarterly Financial Data (Unaudited)
     Consolidated quarterly financial information for 2007 and 2006 is as follows (dollars in thousands, except per share amounts):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                         
    2007 Quarter Ended   2007
    March 31,   June 30,   September 30,   December 31,   Total
Operating revenues
  $ 695,017     $ 862,902     $ 1,205,234     $ 757,985     $ 3,521,138  
Operations and maintenance
    171,578       177,310       178,419       207,398       734,705  
Operating income
    68,221       158,769       338,722       53,319       619,031  
Income taxes
    9,041       40,713       92,055       10,638       152,447  
Income from continuing operations
    16,464       79,237       201,718       3,713       301,132  
Net income
    16,530       78,994       208,708       2,911       307,143  
                                         
    2006 Quarter Ended   2006
    March 31,   June 30,   September 30,   December 31,   Total
Operating revenues
  $ 670,206     $ 925,028     $ 1,076,442     $ 730,072     $ 3,401,748  
Operations and maintenance
    178,427       168,332       164,396       180,122       691,277  
Operating income
    57,163       191,197       310,440       60,070       618,870  
Income taxes
    6,793       49,271       98,836       1,518       156,418  
Income from continuing operations
    11,595       110,843       184,179       10,526       317,143  
Net income
    12,455       112,154       184,167       18,479       327,255  
Earnings per share:
                                 
    2007 Quarter Ended
    March 31,   June 30,   September 30,   December 31,
Basic earnings per share:
                               
Income from continuing operations
  $ 0.16     $ 0.79     $ 2.01     $ 0.04  
Net income
    0.17       0.79       2.08       0.03  
 
                               
Diluted earnings per share:
                               
Income from continuing operations
  $ 0.16     $ 0.79     $ 2.00     $ 0.04  
Net income
    0.16       0.78       2.07       0.03  
                                 
    2006 Quarter Ended
    March 31,   June 30,   September 30,   December 31,
Basic earnings per share:
                               
Income from continuing operations
  $ 0.12     $ 1.12     $ 1.85     $ 0.11  
Net income
    0.13       1.13       1.85       0.19  
 
                               
Diluted earnings per share:
                               
Income from continuing operations
  $ 0.12     $ 1.11     $ 1.84     $ 0.10  
Net income
    0.13       1.13       1.84       0.18  
14. Fair Value of Financial Instruments
     We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2007 and 2006 due to their short maturities.
     We hold short-term investments in fixed income securities for purposes other than trading. We believe that the carrying amounts of these investments represent reasonable estimates of their fair values at December 31, 2007 and 2006 due to the short-term reset of interest rates.

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     APS also holds investments in fixed income and domestic equity securities for purposes other than trading in its nuclear decommissioning trust. The December 31, 2007 and 2006 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.
     On December 31, 2007, the carrying value of our long-term debt for Pinnacle West, excluding capitalized lease obligations was $3.29 billion, with an estimated fair value of $3.20 billion. The carrying value of our long-term debt for Pinnacle West excluding capitalized lease obligations was $3.23 billion on December 31, 2006, with an estimated fair value of $3.19 billion. On December 31, 2007, the carrying value of APS’ long-term debt, excluding capitalized lease obligations, was $2.87 billion, with an estimated fair value of $2.79 billion. The carrying value of APS’ long-term debt excluding capital lease obligations was $2.87 billion on December 31, 2006, with an estimated fair value of $2.84 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
15. Earnings Per Share
     The following table presents earnings per weighted-average common share outstanding for the years ended December 31, 2007, 2006 and 2005:
                         
    2007     2006     2005  
Basic earnings per share:
                       
Income from continuing operations
  $ 3.00     $ 3.19     $ 2.31  
Income (loss) from discontinued operations
    0.06       0.10       (0.48 )
 
                 
Earnings per share — basic
  $ 3.06     $ 3.29     $ 1.83  
 
                 
Diluted earnings per share:
                       
Income from continuing operations
  $ 2.99     $ 3.17     $ 2.31  
Income (loss) from discontinued operations
    0.06       0.10       (0.49 )
 
                 
Earnings per share — diluted
  $ 3.05     $ 3.27     $ 1.82  
 
                 
     Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 579,000 shares in 2007, 593,000 shares in 2006 and 106,000 shares in 2005. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 100,834,871 shares in 2007, 100,010,108 shares in 2006 and 96,589,949 shares in 2005.
     Options to purchase 114,213 shares of common stock were outstanding at December 31, 2007 but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 437,401 at December 31, 2006 and 495,367 at December 31, 2005.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. Stock-Based Compensation
     Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and some of our subsidiaries.
     The 2007 Long-Term Incentive Plan (“2007 Plan”) allows Pinnacle West to grant incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, performance cash awards, dividend equivalents and stock to eligible individuals. We have reserved 8 million shares of common stock for issuance under the 2007 plan plus additional shares that become available for issuance under prior stock plans (“Prior Plans”). Under the 2007 Plan, any shares of stock that are potentially deliverable under any award granted under a Prior Plan will be added to the number of shares of stock available for grant under the 2007 Plan if the award expires or is cancelled or terminated without a delivery of such shares to the participant. In addition, any shares of stock that have been issued in connection with any award granted under a Prior Plan will be added to the number of shares available for grant under the 2007 Plan if the award is cancelled, forfeited, or terminated such that those shares are returned to the Company. No more than 500,000 shares of stock may be granted to any one participant during a calendar year. The maximum performance-based award (other than a performance cash award) payable to any one participant during a performance period is 500,000 shares of stock or the cash equivalent. The plan also provides for the granting of new incentive and non-qualified stock options at a price per share equal to at least 100% of the fair market value of the common stock at the time of grant. The terms of the options cannot be longer than 10 years and the options cannot be repriced during their terms.
     The 2002 Long-Term Incentive Plan (“2002 Plan”) relates to outstanding performance shares but no new awards may be granted under the plan. Performance share awards under the 2002 Plan contain performance criteria that affect the number of shares that ultimately vest. Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year performance period. The number of shares each recipient ultimately receives, if any, is based upon the percentile ranking of Pinnacle West’s earnings per share growth rate at the end of the three-year period as compared with the earnings per share growth rate of all relevant companies in a specified utilities index. The fair value of the grant is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Management evaluates the probability of meeting the performance criteria at each balance sheet date and related compensation cost is amortized over the performance period on a straight-line basis. If the goals are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.
     The 1994 Long-Term Incentive Plan (“1994 Plan”) relates to outstanding options but no new awards may be granted under the plan. Options vest by thirds over a three-year period beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also includes outstanding shares of restricted stock.
     In 2006, Retention Unit Awards (“Retention Units”) were granted to key employees. Each Retention Unit represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Retention Units will be redeemed the first business day of calendar years 2007, 2008, 2009 and 2010. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. The Retention Units vest over a four-year period from 2006 through 2009, unless the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
employee is eligible to retire, in which case the employee’s Retention Units are immediately vested and the compensation expense is immediately recognized. As this award is accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, are remeasured at each balance sheet date, using Pinnacle West’s closing stock price. The amount of cash to settle the payment on the first business day of 2007 was $1.6 million.
     In 2007 under the 2007 Plan, Restricted Stock Unit Awards (“Restricted Stock Units”) were granted to officers and key employees. Each officer and key employee had to elect to receive payment for the vested Restricted Stock Units in cash or in fully transferable shares of stock. The fair value of the stock election is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Each Restricted Stock Unit cash election represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Restricted Stock Units will be redeemed February 20th of calendar years 2008, 2009, 2010 and 2011. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the Restricted Stock Unit from the date of grant to the date of payment plus interest. Restricted Stock Units vest over a four-year period from 2007 through 2010, unless the employee is eligible to retire, in which case the employee’s Restricted Stock Units are immediately vested (with the same redemption dates) and the compensation expense is immediately recognized; however, the Restricted Stock Units will be redeemed on the pre-established valuation dates. As the Restricted Stock Unit cash election award is accounted for as a liability award, the fair market value of the outstanding Restricted Stock Unit cash election is measured at each balance sheet date, using Pinnacle West’s closing stock price.
     The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $6 million in 2007, $13 million in 2006 and $6 million in 2005. The compensation cost that Pinnacle West has capitalized was immaterial in 2007, 2006 and 2005. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $2 million in 2007, $5 million in 2006 and $2 million in 2005. APS’ share of compensation cost that has been charged against income was $6 million in 2007, $12 million in 2006 and $5 million in 2005.
     The following table is a summary of option activity under our equity incentive plans as of December 31, 2007 and changes during the year:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                 
                    Weighted-    
                    Average   Aggregate
            Weighted-   Remaining   Intrinsic Value
    Shares   Average Exercise   Contractual Term   (dollars in
Options   (in thousands)   Price   (Years)   thousands)
Outstanding at January 1, 2007
    1,088     $ 40.64                  
Exercised
    207       39.48                  
Forfeited or expired
    20       43.64                  
 
                               
Outstanding at December 31, 2007
    861       40.84       3.0     $ 2,187  
 
                               
Exercisable at December 31, 2007
    861       40.84       3.0     $ 2,187  
 
                               
     There were no options granted during the years 2005 through 2007. The intrinsic value of options exercised was $2 million for 2007, $5 million for 2006 and $4 million for 2005.
     The following table is a summary of the status of stock compensation awards, other than options, as of December 31, 2007 and changes during the year:
                 
    Shares   Weighted-Average Grant-Date
Nonvested shares   (in thousands)   Fair Value
Nonvested at January 1, 2007
    429     $ 41.45  
Granted
    164       48.02  
Vested
    147       41.38  
Forfeited
    67       42.40  
 
               
Nonvested at December 31, 2007
    379       43.64  
 
               
     As of December 31, 2007, there was $7 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 1.3 years. The total fair value of shares vested during 2007 was $6 million, $10 million for 2006 and $3 million for 2005.
     The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2007, 2006 and 2005:

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                                         
    2007   2007 Grant   2006   2006 Grant           2005 Grant
    Shares/   Date Fair   Shares/   Date Fair   2005   Date Fair
    Units   Value (a)   Units   Value (a)   Shares   Value (a)
Restricted stock award units
    27,026         $ 46.58           $           $  
Restricted cash award units
    107,891             46.58                            
Performance share awards
    134,917             48.42         274,070       41.50       215,300       41.36  
Stock ownership incentive awards
                      12,526       41.50       13,114       44.13  
Retention unit awards
                      123,197       49.92              
Special grant
    2,000           41.88                            
 
(a)   Restricted stock units, performance shares, special grant and stock ownership incentive awards priced at the closing market price on the grant date.
     Cash received from options exercised under our share-based payment arrangements was $8 million for 2007, $22 million for 2006 and $17 million for 2005. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was $1 million for 2007, $2 million for 2006 and $1 million for 2005.
     Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares during 2008.
17. Business Segments
     Pinnacle West’s two reportable business segments are:
    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 2007, 2006 and 2005 is provided as follows (dollars in millions):

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                 
    Business Segments for the Year Ended December 31, 2007  
    Regulated                    
    Electricity     Real Estate              
    Segment     Segment     All other (a)     Total  
Operating revenues
  $ 2,918     $ 212     $ 391     $ 3,521  
Purchased power and fuel costs
    1,141             294       1,435  
Other operating expenses
    836       193       66       1,095  
 
                       
Operating margin
    941       19       31       991  
Depreciation and amortization
    366       4       2       372  
Interest expense
    180       4       2       186  
Other expense (income)
    (18 )     (10 )     8       (20 )
 
                       
Income from continuing operations before income taxes
    413       21       19       453  
Income taxes
    139       7       6       152  
 
                       
Income from continuing operations
    274       14       13       301  
Income from discontinued operations — net of income tax expense of $6 million (see Note 22)
          9       (3 )     6  
 
                       
Net income
  $ 274     $ 23     $ 10     $ 307  
 
                       
Total assets
  $ 10,356     $ 661     $ 145     $ 11,162  
 
                       
Capital expenditures
  $ 900     $ 161     $ 3     $ 1,064  
 
                       
                                 
    Business Segments for the Year Ended December 31, 2006  
    Regulated                    
    Electricity     Real Estate              
    Segment     Segment     All other (a)     Total  
Operating revenues
  $ 2,635     $ 400     $ 367     $ 3,402  
Purchased power and fuel costs
    960             291       1,251  
Other operating expenses
    791       325       57       1,173  
 
                       
Operating margin
    884       75       19       978  
Depreciation and amortization
    354       3       2       359  
Interest expense
    173       1       2       176  
Other expense (income)
    (22 )     (11 )     2       (31 )
 
                       
Income from continuing operations before income taxes
    379       82       13       474  
Income taxes
    120       32       5       157  
 
                       
Income from continuing operations
    259       50       8       317  
Income from discontinued operations — net of income tax expense of $7 million (see Note 22)
          10             10  
 
                       
Net income
  $ 259     $ 60     $ 8     $ 327  
 
                       
Total assets
  $ 10,001     $ 591     $ 226     $ 10,818  
 
                       
Capital expenditures
  $ 662     $ 201     $ 7     $ 870  
 
                       

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                 
    Business Segments for the Year Ended December 31, 2005  
    Regulated                    
    Electricity     Real Estate              
    Segment     Segment     All other (a)     Total  
Operating revenues (b)
  $ 2,237     $ 338     $ 413     $ 2,988  
Purchased power and fuel costs
    595             293       888  
Other operating expenses
    740       278       80       1,098  
Regulatory disallowance (see Note 3)
    139                   139  
 
                       
Operating margin
    763       60       40       863  
Depreciation and amortization
    343       3       2       348  
Interest expense
    169       2       2       173  
Other expense (income)
    (6 )     (3 )     1       (8 )
 
                       
Income from continuing operations before income taxes
    257       58       35       350  
Income taxes
    90       23       14       127  
 
                       
Income from continuing operations
    167       35       21       223  
Income (loss) from discontinued operations — net of income tax benefit of $(30) (see Note 22) (c)
          17       (64 )     (47 )
 
                       
Net income (loss)
  $ 167     $ 52     $ (43 )   $ 176  
 
                       
Capital expenditures
  $ 811     $ 106     $ 11     $ 928  
 
                       
 
(a)   All other activities relate to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.
 
(b)   Effective April 1, 2005, revenues of approximately $40 million from Off-System Sales, which were previously reported in the other segment, began being reported in the regulated electricity segment in accordance with the retail rate case settlement.
 
(c)   The other segment primarily relates to the sale and operations of Silverhawk. See Note 22.
18. Derivative and Energy Trading Accounting
     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of December 31, 2007, we hedged certain exposures to the price variability of commodities for a maximum of 39 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.
     We recognize all derivatives, except those which qualify for a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales exception and are accounted for under the accrual method of accounting. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value of an asset or liability.
     For its regulated operations, APS defers for future rate recovery 90% of gains and losses on derivatives that would otherwise be recognized in income. In the following discussion, amounts that would otherwise be recognized in income will be recorded as either a regulatory asset or liability and have no effect on earnings to the extent these amounts are eligible to be recovered through the PSA.
     We assess hedge effectiveness both at inception and on a continuing basis. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated and is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.
     Both non-trading and trading derivatives that do not qualify for a scope exception are classified as assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge accounting treatment. Non-trading derivatives, or any portion thereof that are not effective hedges, are adjusted to fair value through income. Realized gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.
     All gains and losses (realized and unrealized) on trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis. Trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
     In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Consolidated Statement of Income, but this does not impact our financial condition, net income or cash flows.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Flow Hedges
     The changes in the fair value of our hedged positions included in the Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2007, 2006 and 2005 are comprised of the following (dollars in thousands):
                         
    2007   2006   2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting
  $ 1,430     $ (5,666 )   $ 14,289  
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness
          (10 )     620  
Gains from the discontinuance of cash flow hedges
    320       453       556  
     During 2008, we estimate that a net gain of $18 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 3).
     The following table summarizes our assets and liabilities from risk management and trading activities in accordance with FIN 39-1 at December 31, 2007 and 2006 (dollars in thousands):
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
December 31, 2007   Assets     Assets     Liabilities     Other     (Liability)  
Mark-to-market
  $ 26,333     $ 48,928     $ (30,786 )   $ (4,701 )   $ 39,774  
Margin account
    30,650             6,148             36,798  
Collateral provided to counterparties
    622             128             750  
Collateral provided from counterparties
                             
 
                             
Total
  $ 57,605     $ 48,928     $ (24,510 )   $ (4,701 )   $ 77,322  
 
                             

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
December 31, 2006   Assets     Assets     Liabilities     Other     (Liability)  
Mark-to-market
  $ 119,486     $ 66,810     $ (99,364 )   $ (71,608 )   $ 15,324  
Collateral provided to counterparties
    4,027             2,701       3,259       9,987  
Collateral provided from counterparties
    (54,000 )           (90 )           (54,090 )
Margin account, options and emission allowances — at cost
    43,034       839       19,689             63,562  
 
                             
Total
  $ 112,547     $ 67,649     $ (77,064 )   $ (68,349 )   $ 34,783  
 
                             
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $31 million at December 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.
     See Note 23 for discussion of the adoption of FIN 39-1.
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 12% of Pinnacle West’s $106 million of risk management and trading assets as of December 31, 2007. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ securities is 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 net income 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. See Note 1 “Derivative Accounting” for a discussion of our credit valuation adjustment policy.
19. Other Income and Other Expense
     The following table provides detail of other income and other expense for 2007, 2006 and 2005 (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         
    2007     2006     2005  
Other income:
                       
Interest income
  $ 11,656     $ 18,867     $ 14,793  
SunCor other income (a)
    10,702       10,881       2,623  
SO2 emission allowance sales and other (b)
          10,782       3,187  
Investment gains — net
          2,537       752  
Miscellaneous
    2,336       949       2,005  
 
                 
Total other income
  $ 24,694     $ 44,016     $ 23,360  
 
                 
 
                       
Other expense:
                       
Non-operating costs (b)
  $ (14,021 )   $ (16,223 )   $ (13,589 )
Asset dispositions
          (2,056 )     (9,759 )
Investment losses — net
    (2,339 )            
Miscellaneous
    (9,523 )     (9,521 )     (3,368 )
 
                 
Total other expense
  $ (25,883 )   $ (27,800 )   $ (26,716 )
 
                 
 
(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).
20. 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 (see Note 9).
     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 December 31, 2007, APS would have been required to assume approximately $194 million of debt and pay the equity participants approximately $170 million.
     SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $38 million at December 31, 2007 and $39 million at December 31, 2006.
21. 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 and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related

112


 

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
products and commodity energy. 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 Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our 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 December 31, 2007 are as follows (dollars in millions):
                                 
    Guarantees     Surety Bonds  
            Term             Term  
    Amount     (in years)     Amount     (in years)  
Parental:
                               
Pinnacle West Marketing & Trading
  $ 25       1     $        
APSES
    18       1       20       1  
APS
    4       1              
 
                           
Total
  $ 47             $ 20          
 
                           
     At December 31, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in 2009. 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 December 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 $83 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 December 31, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2008. 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.
22. Discontinued Operations
     SunCor (real estate segment) - In 2007, 2006 and 2005, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144. As a result of the sales, we recorded a gain

113


 

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
from discontinued operations of approximately $10 million ($17 million pretax) in 2007; $9 million ($15 million pretax) in 2006; and $15 million ($25 million pretax) in 2005.
     Silverhawk (other) - In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on January 10, 2006. As a result of this sale, we recorded a loss from discontinued operations of approximately $56 million ($91 million pretax) in the second quarter of 2005. The chart below includes the revenues and expenses related to the operations of Silverhawk.
     Other — Includes activities related to APSES in 2007 and to El Dorado in 2006 and 2005.
     The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2007, 2006 and 2005 (dollars in millions):
                         
    2007     2006     2005  
Revenue:
                       
SunCor — commercial operations
  $ 6     $ 3     $ 9  
Silverhawk
          1       95  
 
                 
Total revenue
  $ 6     $ 4     $ 104  
 
                 
 
                       
Income (loss) before taxes:
                       
SunCor — commercial operations
  $ 15     $ 17     $ 28  
Silverhawk (a)
          1       (111 )
Other
    (5 )     (1 )     6  
 
                 
Total income (loss) before taxes
  $ 10     $ 17     $ (77 )
 
                 
 
                       
Income (loss) after taxes:
                       
SunCor — commercial operations
  $ 9     $ 10     $ 17  
Silverhawk
          1       (67 )
Other
    (3 )     (1 )     3  
 
                 
Total income (loss) after taxes
  $ 6     $ 10     $ (47 )
 
                 
 
(a)   Income before income taxes includes an interest expense allocation, net of capitalized amounts, of $13 million in 2005. The allocation was based on Pinnacle West’s weighted-average interest rate applied to the net property, plant and equipment.
23. Subsequent Events
     We adopted FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1) on January 1, 2008. In accordance with this guidance, we elected to offset the fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting arrangement. Collateral was previously reported in other current assets or other current liabilities on our Consolidated Balance Sheet. The guidance requires retrospective application for all prior periods presented. As a result, our Consolidated Balance Sheet and Consolidated Statement of Cash Flows line items decreased by the following amounts (dollars in thousands):

114


 

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         
    As originally   Reclassifications    
    reported in the   as a result of the    
    2007   adoption of   After adoption of
Balance Sheet - December 31, 2007   Form 10-K   FIN 39-1   FIN 39-1
Current Assets — Assets from risk management and trading activities
  $ 97,373     $ (39,768 )   $ 57,605  
Current Assets — Other current assets
    34,738       (750 )     33,988  
Investments and Other Assets — Assets from long-term risk management and trading activities
    89,913       (40,985 )     48,928  
 
                       
Current Liabilities — Liabilities from risk management and trading activities
    65,028       (40,518 )     24,510  
Deferred Credits and Other - Liabilities from long-term risk management and trading activities
    45,686       (40,985 )     4,701  
                         
    As originally   Reclassifications    
    reported in the   as a result of the    
    2007   adoption of   After adoption of
Balance Sheet - December 31, 2006   Form 10-K   FIN 39-1   FIN 39-1
Current Assets — Assets from risk management and trading activities
  $ 641,040     $ (528,493 )   $ 112,547  
Current Assets — Other current assets
    27,078       (9,988 )     17,090  
Investments and Other Assets — Assets from long-term risk management and trading activities
    167,211       (99,562 )     67,649  
 
                       
Current Liabilities — Liabilities from risk management and trading activities
    558,195       (481,131 )     77,064  
Current Liabilities — Other current liabilities
    134,123       (54,091 )     80,032  
Deferred Credits and Other — Liabilities from long-term risk management and trading activities
    171,170       (102,821 )     68,349  

115


 

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         
            Reclassifications    
    As originally   as a result of the    
Statement of Cash Flows —   reported in the   adoption of   After adoption of
Year ended December 31, 2007   2007 Form 10-K   FIN 39-1   FIN 39-1
Change in other long-term assets
  $ 17,390     $ (41,216 )   $ (23,826 )
Change in margin and collateral accounts — assets
          (37,371 )     (37,371 )
Change in risk management and trading — liabilities
    (14,450 )     14,450        
Change in margin and collateral accounts — liabilities
          19,284       19,284  
Collateral
    (44,853 )     44,853        
                         
            Reclassifications    
    As originally   as a result of the    
Statement of Cash Flows —   reported in the   adoption of   After adoption of
Year ended December 31, 2006   2007 Form 10-K   FIN 39-1   FIN 39-1
Change in other long-term assets
  $ 20,330     $ (2,789 )   $ 17,541  
Change in margin and collateral accounts — assets
          (249,792 )     (249,792 )
Change in risk management and trading — liabilities
    (133,197 )     133,197        
Change in margin and collateral accounts — liabilities
          (46,444 )     (46,444 )
Collateral
    (165,828 )     165,828        
                         
            Reclassifications    
    As originally   as a result of the    
Statement of Cash Flows —   reported in the   adoption of   After adoption of
Year ended December 31, 2005   2007 Form 10-K   FIN 39-1   FIN 39-1
Other current assets
  $ (6,815 )   $ 5,420     $ (1,395 )
Change in other long-term assets
    (97,893 )     62,100       (35,793 )
Change in margin and collateral accounts — assets
          251,925       251,925  
Change in risk management and trading — liabilities
    110,393       (110,393 )      
Change in margin and collateral accounts — liabilities
          (17,012 )     (17,012 )
Collateral
    192,040       (192,040 )      
     During the first quarter of 2008, SunCor entered into an agreement to sell certain commercial properties. As a result, we reclassified the related real estate segment revenues, real estate operating

116


 

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
costs, depreciation expense and interest charges to discontinued operations on the 2007 Consolidated Statements of Income and Consolidated Statement of Cash Flows in accordance with SFAS No. 144. See Note 22.

117


 

MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(ARIZONA PUBLIC SERVICE COMPANY)
     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007. The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s financial statements.
February 27, 2008

118


 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2007 and 2006, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

119


 

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As reflected in the statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans effective December 31, 2006.
As discussed in Note 23, the Company adopted the provisions of FASB Staff Position No. FIN 39-1.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 27, 2008
(November 25, 2008 as to the effects of the adoption of FASB Staff Position No. FIN 39-1 as described in Note 23).

120


 

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
(dollars in thousands)
                         
    Year Ended December 31,  
    2007     2006     2005  
Electric Operating Revenues
  $ 2,936,277     $ 2,658,513     $ 2,270,793  
 
                       
Operating Expenses:
                       
Fuel and purchased power
    1,151,392       969,767       688,982  
Operations and maintenance
    710,077       665,631       591,941  
Depreciation and amortization
    365,430       353,057       325,174  
Income taxes (Notes 4 and S-1)
    155,735       144,127       157,273  
Other taxes
    127,648       127,989       125,810  
 
                 
Total
    2,510,282       2,260,571       1,889,180  
 
                 
 
                       
Operating Income
    425,995       397,942       381,613  
 
                 
 
                       
Other Income (Deductions):
                       
Regulatory disallowance (Note 3)
                (138,562 )
Income taxes (Notes 4 and S-1)
    4,578       5,200       59,263  
Allowance for equity funds used during construction
    21,195       14,312       11,191  
Other income (Note S-4)
    16,727       31,902       22,141  
Other expense (Note S-4)
    (21,630 )     (23,830 )     (23,204 )
 
                 
Total
    20,870       27,584       (69,171 )
 
                 
 
                       
Interest Deductions:
                       
Interest on long-term debt
    161,030       149,240       138,476  
Interest on short-term borrowings
    9,564       9,529       7,026  
Debt discount, premium and expense
    4,639       4,363       4,085  
Allowance for borrowed funds used during construction
    (12,308 )     (7,336 )     (7,624 )
 
                 
Total
    162,925       155,796       141,963  
 
                 
 
                       
Net Income
  $ 283,940     $ 269,730     $ 170,479  
 
                 
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

121


 

ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)
                 
    December 31,  
    2007     2006  
ASSETS
               
Utility Plant (Notes 1, 6, 9 and 10)
               
Electric plant in service and held for future use
  $ 11,582,862     $ 11,094,868  
Less accumulated depreciation and amortization
    3,994,777       3,789,534  
 
           
Net
    7,588,085       7,305,334  
 
               
Construction work in progress
    622,693       365,704  
Intangible assets, net of accumulated amortization of $250,268 and $217,099
    105,225       95,601  
Nuclear fuel, net of accumulated amortization of $68,375 and $50,741
    69,271       60,100  
 
           
Total utility plant
    8,385,274       7,826,739  
 
           
 
               
Investments and Other Assets
               
Decommissioning trust accounts (Note 12)
    379,347       343,771  
Assets from risk management and trading activities (Note S-3)
    41,603       5,335  
Other assets
    69,570       67,763  
 
           
Total investments and other assets
    490,520       416,869  
 
           
 
               
Current Assets:
               
Cash and cash equivalents
    52,151       81,870  
Investment in debt securities
          32,700  
Customer and other receivables
    402,244       410,436  
Allowance for doubtful accounts
    (4,265 )     (4,223 )
Materials and supplies (at average cost)
    149,759       125,802  
Fossil fuel (at average cost)
    27,792       21,973  
Assets from risk management and trading activities (Note S-3)
    34,087       67,798  
Deferred income taxes (Notes 4 and S-1)
    38,707       19,220  
Other
    16,545       11,508  
 
           
Total current assets
    717,020       767,084  
 
           
 
               
Deferred Debits:
               
Deferred fuel and purchased power regulatory asset (Notes 1, 3, 4 and S-1)
    110,928       160,268  
Other regulatory assets (Notes 1, 3, 4 and S-1)
    514,353       686,016  
Unamortized debt issue costs
    24,373       26,393  
Other
    78,934       65,397  
 
           
 
               
Total deferred debits
    728,588       938,074  
 
           
 
               
Total Assets
  $ 10,321,402     $ 9,948,766  
 
           
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

122


 

ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)
                 
    December 31,  
    2007     2006  
LIABILITIES AND EQUITY
               
Capitalization:
               
Common stock
  $ 178,162     $ 178,162  
Additional paid-in capital (Note 3)
    2,105,466       2,065,918  
Retained earnings
    1,076,557       960,405  
Accumulated other comprehensive income (loss):
               
Pension and other postretirement benefits (Note 8)
    (21,782 )      
Derivative instruments
    13,038       2,988  
 
           
Common stock equity
    3,351,441       3,207,473  
Long-term debt less current maturities (Note 6)
    2,876,881       2,877,502  
 
           
Total capitalization
    6,228,322       6,084,975  
 
           
 
               
Current Liabilities:
               
Short-term debt
    218,000        
Current maturities of long-term debt (Note 6)
    978       968  
Accounts payable
    239,923       223,417  
Accrued taxes
    374,444       381,444  
Accrued interest
    38,262       45,254  
Customer deposits
    71,376       61,900  
Liabilities from risk management and trading activities (Note S-3)
    19,921       19,445  
Other
    92,802       74,128  
 
           
Total current liabilities
    1,055,706       806,556  
 
           
 
               
Deferred Credits and Other:
               
Deferred income taxes (Notes 4 and S-1)
    1,250,028       1,215,862  
Regulatory liabilities (Notes 1, 3, 4, and S-1)
    642,564       635,431  
Liability for asset retirements (Note 12)
    281,903       268,389  
Pension and other postretirement liabilities (Note 8)
    469,945       551,531  
Customer advances for construction
    94,801       71,211  
Unamortized gain — sale of utility plant (Note 9)
    36,606       41,182  
Liabilities from risk management and trading activities (Note S-3)
    4,573       42,140  
Other
    256,954       231,489  
 
           
Total deferred credits and other
    3,037,374       3,057,235  
 
           
 
               
Commitments and Contingencies (See Notes)
       
 
Total Liabilities and Equity
  $ 10,321,402     $ 9,948,766  
 
           
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

123


 

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
(dollars in thousands)
                         
    Year Ended December 31,  
    2007     2006     2005  
Cash Flows from Operating Activities:
                       
Net income
  $ 283,940     $ 269,730     $ 170,479  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Regulatory disallowance
                138,562  
Depreciation and amortization including nuclear fuel
    395,890       381,173       353,082  
Deferred fuel and purchased power
    (196,136 )     (252,849 )     (172,756 )
Deferred fuel and purchased power amortization
    231,106       265,337        
Deferred fuel and purchased power disallowance
    14,370              
Allowance for equity funds used during construction
    (21,195 )     (14,312 )     (11,191 )
Deferred income taxes
    (44,478 )     (305 )     9,659  
Change in derivative mark-to-market valuations
    (6,758 )     6,893       3,492  
Changes in current assets and liabilities:
                       
Customer and other receivables
    23,882       20,970       (56,152 )
Materials, supplies and fossil fuel
    (29,776 )     (14,381 )     (12,268 )
Other current assets
    (8,056 )     3,666       (2,292 )
Accounts payable
    (2,797 )     5,825       (12,372 )
Accrued taxes
    13,802       23,678       67,454  
Other current liabilities
    20,231       45,125       (37,781 )
Change in margin and collateral accounts — liabilities
    27,624       (166,088 )     126,705  
Change in margin and collateral accounts — assets
    11,252       (205,752 )     173,019  
Changes in unrecognized tax benefits
    27,773              
Change in other long-term assets
    (23,577 )     2,828       (24,752 )
Change in other long-term liabilities
    48,718       22,175       9,002  
 
                 
Net cash flow provided by operating activities
    765,815       393,713       721,890  
 
                 
Cash Flows from Investing Activities:
                       
Capital expenditures
    (882,357 )     (648,743 )     (609,857 )
Transfer of PWEC Dedicated Assets to APS
                (500,000 )
Purchase of Sundance Plant
                (185,046 )
Allowance for borrowed funds used during construction
    (12,308 )     (7,336 )     (7,624 )
Purchases of investment securities
    (36,525 )     (1,291,903 )     (1,476,623 )
Proceeds from sale of investment securities
    69,225       1,259,203       1,657,798  
Proceeds from nuclear decommissioning trust sales
    259,026       254,651       186,215  
Investment in nuclear decommissioning trust
    (279,768 )     (275,393 )     (204,633 )
Repayment of loan by Pinnacle West Energy
                500,000  
Other
    1,211       (4,470 )     (5,372 )
 
                 
Net cash flow used for investing activities
    (881,496 )     (713,991 )     (645,142 )
 
                 
Cash Flows from Financing Activities:
                       
Issuance of long-term debt
          395,481       411,787  
Short-term borrowings — net
    218,000              
Equity infusion
    39,548       212,820       250,000  
Dividends paid on common stock
    (170,000 )     (170,000 )     (170,000 )
Repayment and reacquisition of long-term debt
    (1,586 )     (86,086 )     (568,177 )
 
                 
Net cash flow (used for) provided by financing activities
    85,962       352,215       (76,390 )
 
                 
Net (decrease) increase in cash and cash equivalents
    (29,719 )     31,937       358  
Cash and cash equivalents at beginning of year
    81,870       49,933       49,575  
 
                 
Cash and cash equivalents at end of year
  $ 52,151     $ 81,870     $ 49,933  
 
                 
Supplemental disclosure of cash flow information:
                       
Cash paid during the year for:
                       
Income taxes, net of refunds
  $ 186,183     $ 117,831     $ 34,252  
Interest, net of amounts capitalized
  $ 165,279     $ 131,183     $ 146,207  
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

124


 

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)
                         
    Year Ended December 31,  
    2007     2006   2005  
COMMON STOCK
  $ 178,162     $ 178,162     $ 178,162  
 
                 
 
                       
ADDITIONAL PAID-IN CAPITAL
    2,105,466       2,065,918       1,853,098  
 
                 
 
                       
RETAINED EARNINGS
                       
Balance at beginning of year
    960,405       860,675       860,196  
Net income
    283,940       269,730       170,479  
Common stock dividends
    (170,000 )     (170,000 )     (170,000 )
Cumulative effect of change in accounting for income taxes (Note S-1)
    2,212              
 
                 
Balance at end of year
    1,076,557       960,405       860,675  
 
                 
 
                       
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
                       
Balance at beginning of year
    2,988       93,290       (52,760 )
Pension and other postretirement benefits (Note 8):
                       
Unrealized actuarial loss, net of tax benefit of ($15,126)
    (23,304 )            
Prior service cost, net of tax benefit of ($463)
    (713 )            
Amortization to income:
                       
Actuarial loss, net of tax expense of $1,238
    1,908              
Prior service cost, net of tax expense of $212
    327              
Minimum pension liability adjustment, net of tax expense (benefit) of $27,424 and ($9,023)
          42,731       (15,045 )
Adjustment to reflect a change in accounting, net of tax expense of $27,760
          43,401        
Derivative instruments:
                       
Net unrealized gain (loss), net of tax expense (benefit) of $1,369, ($111,367) and $140,135
    2,040       (173,872 )     218,656  
Reclassification of net realized (gains) losses to income, net of tax expense (benefit) of $5,164, ($1,657) and ($37,082)
    8,010       (2,562 )     (57,561 )
 
                 
Balance at end of year
    (8,744 )     2,988       93,290  
 
                 
 
                       
TOTAL COMMON STOCK EQUITY
  $ 3,351,441     $ 3,207,473     $ 2,985,225  
 
                 
 
                       
COMPREHENSIVE INCOME
                       
Net income
  $ 283,940     $ 269,730     $ 170,479  
Other comprehensive income (loss)
    (11,732 )     (133,703 )     146,050  
 
                 
Total comprehensive income
  $ 272,208     $ 136,027     $ 316,529  
 
                 
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

125


 

     Certain notes to Arizona Public Service Company’s financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.
         
        APS’
    Consolidated   Supplemental
    Footnote   Footnote
    Reference   Reference
Summary of Significant Accounting Policies
  Note 1  
New Accounting Standards
  Note 2  
Regulatory Matters
  Note 3  
Income Taxes
  Note 4   Note S-1
Lines of Credit and Short-Term Borrowings
  Note 5  
Long-Term Debt
  Note 6  
Common Stock and Treasury Stock
  Note 7  
Retirement Plans and Other Benefits
  Note 8  
Leases
  Note 9  
Jointly-Owned Facilities
  Note 10  
Commitments and Contingencies
  Note 11  
Asset Retirement Obligations
  Note 12  
Selected Quarterly Financial Data (Unaudited)
  Note 13   Note S-2
Fair Value of Financial Instruments
  Note 14  
Earnings Per Share
  Note 15  
Stock-Based Compensation
  Note 16  
Business Segments
  Note 17  
Derivative and Energy Trading Accounting
  Note 18   Note S-3
Other Income and Other Expense
  Note 19   Note S-4
Variable Interest Entities
  Note 20  
Guarantees
  Note 21  
Discontinued Operations
  Note 22  
Related Party Transactions
    Note S-5
Subsequent Events
  Note 23   Note S-6

126


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
S-1. Income Taxes
     APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’ taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.
     Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.
     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 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. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next six months, we expect that the IRS will finalize its examination of the 2001 return, which will include a settlement on the tax accounting method change. Although the ultimate outcome of this matter cannot currently be predicted, the current status of the examination has resulted in changes in our judgment which are reflected in the reconciliation of the total amounts of unrecognized tax benefits presented below. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows. We do not expect that there will be any other significant increases or decreases in our unrecognized tax benefits within the next 12 months.
     We adopted FIN 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.
     Following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Balance Sheets (dollars in thousands):

127


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
         
Total unrecognized tax benefits, January 1, 2007
  $ 126,700  
Additions for tax positions of the current year
     
Additions for tax positions of prior years
    66,610  
Reductions for tax positions of prior years for:
       
Changes in judgment
    (37,419 )
Settlements with taxing authorities
    (1,418 )
Lapses of applicable statute of limitations
     
 
     
Total unrecognized tax benefits, December 31, 2007
  $ 154,473  
 
     
     Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately $4 million of tax positions that, if recognized, would decrease our effective tax rate.
     We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of operations as income tax expense. For 2007, the amount of interest recognized in the statement of operations related to unrecognized tax benefits was $3 million.
     As of December 31, 2007, the total amount of interest expense recognized in the statement of financial position related to unrecognized tax benefits was $56 million. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, we have recognized $5 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 components of APS’ income tax expense are as follows (dollars in thousands):
                         
    Year Ended December 31,  
    2007     2006     2005  
Current:
                       
Federal
  $ 168,607     $ 114,971     $ 79,917  
State
    27,028       21,442       8,434  
 
                 
Total current
    195,635       136,413       88,351  
Deferred
    (44,478 )     2,514       9,659  
 
                 
Total income tax expense
  $ 151,157     $ 138,927     $ 98,010  
 
                 
     On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.
     The following chart compares APS’ pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):

128


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
                         
    Year Ended December 31,  
    2007     2006     2005  
Federal income tax expense at 35% statutory rate
  $ 152,284     $ 143,030     $ 93,971  
Increases (reductions) in tax expense resulting from:
                       
State income tax net of federal income tax benefit
    17,540       15,684       8,986  
Credits and favorable adjustments related to prior years resolved in current year
    (11,432 )     (10,518 )      
Medicare Subsidy Part-D
    (3,100 )     (3,036 )     (2,465 )
Allowance for equity funds used during construction (see Note 1)
    (6,900 )     (4,656 )     (3,694 )
Other
    2,765       (1,577 )     1,212  
 
                 
Income tax expense
  $ 151,157     $ 138,927     $ 98,010  
 
                 
     The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):
                 
    December 31,  
    2007     2006  
Current asset
  $ 38,707     $ 19,220  
Long-term liability
    (1,250,028 )     (1,215,862 )
 
           
Accumulated deferred income taxes — net
  $ (1,211,321 )   $ (1,196,642 )
 
           

129


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
     The components of the net deferred income tax liability were as follows (dollars in thousands):
                 
    December 31,  
    2007     2006  
DEFERRED TAX ASSETS
               
Regulatory liabilities:
               
Asset retirement obligation
  $ 214,607     $ 203,846  
Federal excess deferred income tax
    11,091       12,714  
Tax benefit of Medicare subsidy
    11,727       18,214  
Other
    26,579       27,283  
Risk management and trading activities
    12,112       37,468  
Pension and other postretirement liabilities
    197,620       257,910  
Deferred gain on Palo Verde Unit 2 sale-leaseback
    14,408       16,160  
Other
    116,491       86,442  
 
           
Total deferred tax assets
    604,635       660,037  
 
           
DEFERRED TAX LIABILITIES
               
Plant-related
    (1,538,183 )     (1,509,812 )
Risk management and trading activities
    (17,483 )     (13,160 )
Regulatory assets:
               
Deferred fuel and purchased power
    (43,661 )     (62,889 )
Deferred fuel and purchased power — mark-to-market
    (2,782 )     (24,427 )
Pension and other postretirement benefits
    (133,120 )     (185,602 )
Other
    (80,727 )     (60,789 )
 
           
Total deferred tax liabilities
    (1,815,956 )     (1,856,679 )
 
           
Accumulated deferred income taxes — net
  $ (1,211,321 )   $ (1,196,642 )
 
           

130


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
S-2. Selected Quarterly Financial Data (Unaudited)
     Quarterly financial information for 2007 and 2006 is as follows (dollars in thousands):
                                         
    2007 Quarter Ended,   2007
    March 31,   June 30,   September 30,   December 31,   Total
Operating revenues
  $ 538,260     $ 721,759     $ 1,047,062     $ 629,196     $ 2,936,277  
Operations and maintenance
    165,934       170,631       171,963       201,549       710,077  
Operating income
    40,589       109,643       238,144       37,619       425,995  
Net income
    4,317       75,090       204,257       276       283,940  
                                         
    2006 Quarter Ended,   2006
    March 31,   June 30,   September 30,   December 31,   Total
Operating revenues
  $ 476,869     $ 718,850     $ 886,686     $ 576,108     $ 2,658,513  
Operations and maintenance
    173,353       164,373       156,170       171,735       665,631  
Operating income
    25,044       119,967       200,580       52,351       397,942  
Net income (loss)
    (5,521 )     93,757       168,634       12,860       269,730  
S-3. Derivative and Energy Trading Accounting
     APS is exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels and emissions allowances and credits. As of December 31, 2007, APS hedged certain exposures to these risks for a maximum of 39 months.
Cash Flow Hedges
     The changes in the fair value of APS’ hedged positions included in the APS Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2007, 2006 and 2005 are comprised of the following (dollars in thousands):
                         
    2007   2006   2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting
  $ 1,430     $ (5,666 )   $ 14,452  
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness
          (10 )     620  
Gains from the discontinuance of cash flow hedges
    150       178       473  
     During 2008, APS estimates that a net gain of $1 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 3).

131


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
     The following table summarizes our assets and liabilities from risk management and trading activities in accordance with FIN 39-1 at December 31, 2007 and 2006 (dollars in thousands):
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and        
December 31, 2007   Assets     Assets     Liabilities     Other     Net Asset  
Mark-to-market
  $ 2,815     $ 41,603     $ (26,197 )   $ (4,573 )   $ 13,648  
Margin account
    30,650             6,148             36,798  
Collateral provided to counterparties
    622             128             750  
Collateral provided from counterparties
                             
 
                             
Total
  $ 34,087     $ 41,603     $ (19,921 )   $ (4,573 )   $ 51,196  
 
                             
                                         
            Investments             Deferred        
    Current     and Other     Current     Credits and     Net Asset  
December 31, 2006   Assets     Assets     Liabilities     Other     (Liability)  
Mark-to-market
  $ 25,274     $ 5,335     $ (51,985 )   $ (43,499 )   $ (64,875 )
Collateral provided to counterparties
                500       1,359       1,859  
Collateral provided from counterparties
    (510 )           (90 )           (600 )
Margin account and options at cost
    43,034             32,130             75,164  
 
                             
Total
  $ 67,798     $ 5,335     $ (19,445 )   $ (42,140 )   $ 11,548  
 
                             
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $31 million at December 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.
     See Note S-6 for discussion of the adoption of FIN 39-1.
S-4. Other Income and Other Expense
     The following table provides detail of APS’ other income and other expense for 2007, 2006 and 2005 (dollars in thousands):

132


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
                         
    2007     2006     2005  
Other income:
                       
Interest income
  $ 10,961     $ 16,526     $ 14,513  
SO2 emission allowance sales and other (a)
    1,001       10,782       3,187  
Investment gains — net
    2,429       3,645       1,705  
Miscellaneous
    2,336       949       2,736  
 
                 
Total other income
  $ 16,727     $ 31,902     $ 22,141  
 
                 
 
                       
Other expense:
                       
Non-operating costs (a)
  $ (12,712 )   $ (15,415 )   $ (11,706 )
Asset dispositions
    (1,981 )     (1,851 )     (9,759 )
Miscellaneous
    (6,937 )     (6,564 )     (1,739 )
 
                 
Total other expense
  $ (21,630 )   $ (23,830 )   $ (23,204 )
 
                 
 
(a)   As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).
S-5. Related Party Transactions
     From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other subsidiaries. The following table summarizes the amounts included in the APS Statements of Income and Balance Sheets related to transactions with affiliated companies (dollars in millions):
                         
    Year Ended December 31,  
    2007     2006     2005  
Electric operating revenues:
                       
Pinnacle West Marketing & Trading(a)
  $ 4     $ 6     $ 6  
Pinnacle West Energy
                2  
 
                 
Total
  $ 4     $ 6     $ 8  
 
                 
 
                       
Fuel and purchased power costs:
                       
Pinnacle West Energy
  $     $     $ 61  
 
                       
Other:
                       
Pinnacle West Energy interest income
  $     $     $ 7  
Equity infusion from Pinnacle West
  $ 40     $ 210     $ 250  
 
(a)   Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

133


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
                 
    As of December 31,  
    2007     2006  
Net affiliate receivables (payables):
               
Pinnacle West Marketing & Trading (a)
  $ 11     $ 2  
APSES
          1  
Pinnacle West
    (9 )     (20 )
 
           
Total
  $ 2     $ (17 )
 
           
 
(a)   Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.
     Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. However, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.”
     On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consisted of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006. In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.
     Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.
S-6. Subsequent Events
     APS adopted FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1) on January 1, 2008. In accordance with this guidance, APS elected to offset the fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting arrangement. Collateral was previously reported in other current assets or other current liabilities on our Consolidated Balance Sheet. The guidance requires retrospective application for all prior periods presented. As a result, APS’ Balance Sheet and Statement of Cash Flows line items decreased by the following amounts (dollars in thousands):

134


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
                         
    As originally   Reclassifications    
    reported in the   as a result of the    
    2007   adoption of   After adoption of
Balance Sheet - December 31, 2007   Form 10-K   FIN 39-1   FIN 39-1
Current Assets — Assets from risk management and trading activities
  $ 73,854     $ (39,767 )   $ 34,087  
Current Assets — Other current assets
    17,296       (751 )     16,545  
Investments and Other Assets — Assets from long-term risk management and trading activities
    82,588       (40,985 )     41,603  
 
                       
Current Liabilities — Liabilities from risk management and trading activities
    60,439       (40,518 )     19,921  
Deferred Credits and Other - Liabilities from long-term risk management and trading activities
    45,558       (40,985 )     4,573  
                         
    As originally   Reclassifications    
    reported in the   as a result of the    
    2007   adoption of   After adoption of
Balance Sheet - December 31, 2006   Form 10-K   FIN 39-1   FIN 39-1
Current Assets — Assets from risk management and trading activities
  $ 539,308     $ (471,510 )   $ 67,798  
Current Assets — Other current assets
    13,367       (1,859 )     11,508  
Investments and Other Assets — Assets from long-term risk management and trading activities
    96,892       (91,557 )     5,335  
 
                       
Current Liabilities — Liabilities from risk management and trading activities
    490,855       (471,410 )     19,445  
Current Liabilities — Other current liabilities
    74,728       (600 )     74,128  
Deferred Credits and Other - Liabilities from long-term risk management and trading activities
    135,056       (92,916 )     42,140  

135


 

NOTES TO ARIZONA PUBLIC SERVICE COMPANY
                         
            Reclassifications        
    As originally     as a result of the        
Statement of Cash Flows —   reported in the     adoption of     After adoption of  
Year ended December 31, 2007   2007 Form 10-K     FIN 39-1     FIN 39-1  
Change in risk management and trading — assets
  $ 40,376     $ (40,376 )   $  
Change in margin and collateral accounts — assets
          11,252       11,252  
Change in risk management and trading — liabilities
    (2,009 )     2,009        
Change in margin and collateral accounts — liabilities
          27,624       27,624  
Collateral
    509       (509 )      
                         
            Reclassifications    
    As originally   as a result of the    
Statement of Cash Flows —   reported in the   adoption of   After adoption of
Year ended December 31, 2006   2007 Form 10-K   FIN 39-1   FIN 39-1
Change in risk management and trading — assets
  $ (74,208 )   $ 74,208     $  
Change in margin and collateral accounts — assets
          (205,752 )     (205,752 )
Change in risk management and trading — liabilities
    (121,833 )     121,833        
Change in margin and collateral accounts — liabilities
          (166,088 )     (166,088 )
Collateral
    (175,799 )     175,799        
                         
            Reclassifications    
    As originally   as a result of the    
Statement of Cash Flows —   reported in the   adoption of   After adoption of
Year ended December 31, 2005   2007 Form 10-K   FIN 39-1   FIN 39-1
Other current assets
  $ (2,592 )   $ 300     $ (2,292 )
Change in risk management and trading — assets
    15,449       (15,449 )      
Change in margin and collateral accounts — assets
          173,019       173,019  
Change in risk management and trading — liabilities
    115,495       (115,495 )      
Change in margin and collateral accounts — liabilities
          126,705       126,705  
Collateral
    169,080       (169,080 )      

136


 

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME
(in thousands)
                         
    Year Ended December 31,  
    2007 (a)     2006     2005  
Operating revenues
  $ 6,708     $ 119,224     $ 154,053  
 
                 
 
                       
Operating expenses
                       
Fuel and purchased power
    (35,541 )     101,360       95,223  
Other operating expenses
    5,659       9,607       3,268  
 
                 
Total
    (29,882 )     110,967       98,491  
 
                 
 
                       
Operating income
    36,590       8,257       55,562  
 
                       
Other
                       
Equity in earnings of subsidiaries
    287,078       324,504       58,759  
Other income
    225       2,208       5,337  
 
                 
Total
    287,303       326,712       64,096  
 
                       
Interest expense
    17,190       20,522       16,472  
 
                 
 
                       
Income from continuing operations
    306,703       314,447       103,186  
 
                       
Income tax benefit
    (440 )     (12,898 )     (62,761 )
 
                 
 
                       
Income from continuing operations — net of income taxes
    307,143       327,345       165,947  
Income (loss) from discontinued operations
          (90 )     10,320  
 
                 
 
                       
Net income
  $ 307,143     $ 327,255     $ 176,267  
 
                 
 
(a)   Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

137


 

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(in thousands)
                 
    Balance at December 31,  
    2007 (a)     2006  
Assets
               
 
               
Current assets
               
Cash and cash equivalents
  $ 137     $ 11  
Customer and other receivables
    82,003       174,583  
Allowance for doubtful accounts
          (1,200 )
Assets from risk management and trading activities
          44,620  
Other current assets
    1,262       2,682  
 
           
Total current assets
    83,402       220,696  
 
           
 
               
Investments and other assets
               
Assets from long-term risk management and trading activities
          62,314  
Investments in subsidiaries
    3,711,737       3,545,329  
Deferred income taxes
    11,806        
Other assets
    23,591       73,300  
 
           
Total investments and other assets
    3,747,134       3,680,943  
 
           
 
               
Total Assets
  $ 3,830,536     $ 3,901,639  
 
           
 
               
Liabilities and Common Stock Equity
               
 
               
Current liabilities
               
Accounts payable
  $ 22,177     $ 80,903  
Accrued taxes
    (86,081 )     (118,073 )
Short-term borrowings
    115,000       27,900  
Current maturities of long-term debt
          115  
Deferred income taxes
    7,682       18,238  
Liabilities from risk management and trading activities
    2       57,618  
Other current liabilities
    18,019       77,495  
 
           
Total current liabilities
    76,799       144,196  
 
           
 
               
Long-term debt less current maturities
    175,000       175,000  
 
               
Deferred credits and other
           
Deferred income taxes
          19,582  
Pension and other postretirement liabilities
    22,248       13,437  
Liabilities from risk management and trading activities
          26,209  
Other
    24,878       23,218  
 
           
Total deferred credits and other
    47,126       82,446  
 
           
 
               
Common stock equity
               
Common stock
    2,133,733       2,587,201  
Accumulated other comprehensive income (loss)
    (15,863 )     17,512  
Retained earnings
    1,413,741       895,284  
 
           
Total common stock equity
    3,531,611       3,499,997  
 
           
 
               
Total Liabilities and Common Stock Equity
  $ 3,830,536     $ 3,901,639  
 
           
 
(a)   Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

138


 

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
                         
    Year Ended December 31  
    2007 (a)     2006     2005  
Cash flows from operating activities
           
Net Income
  $ 307,143     $ 327,255     $ 176,267  
Less: equity in earnings of subsidiaries — net
    (287,078 )     (324,504 )     (58,759 )
 
                 
Net income attributable to Pinnacle West
    20,065       2,751       117,508  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    320       470       551  
Deferred income taxes
    (24,192 )     30,384       (19,929 )
Change in mark-to-market valuations
    53,228       21,698       (15,162 )
Customer and other receivables
    112,543       2,816       1,730  
Accounts payable
    (57,978 )     (55,675 )     43,969  
Accrued taxes
    25,127       (49,529 )     (84,758 )
Change in margin and collateral accounts — net
    (11,602 )     75,605       (64,810 )
Other net
    (104,968 )     (30,718 )     84,592  
 
                 
Net cash flow (used for) provided by operating activities
    12,543       (2,198 )     63,691  
 
                 
 
                       
Cash flows from investing activities
                       
Investments in and advances to subsidiaries — net
    (83,993 )     (4,677 )     (230,229 )
Repayments and advances of loans from subsidiaries
    (4,800 )     2,686       2,402  
Dividends received from subsidiaries
    180,000       180,000       220,000  
Purchases of investment securities
          (147,501 )     (1,485,655 )
Proceeds from sale of investment securities
          147,501       1,485,683  
 
                 
Net cash flow (used for) provided by investing activities
    91,207       178,009       (7,799 )
 
                 
 
                       
Cash flows from financing activities
                       
Issuance of long-term debt
          175,000        
Short-term borrowings and payments — net
    87,371       27,900        
Dividends paid on common stock
    (210,473 )     (201,221 )     (186,677 )
Repayment of long-term debt
    (115 )     (298,687 )     (165,104 )
Common stock equity issuance
    19,593       35,834       290,542  
 
                 
Net cash flow used for financing activities
    (103,624 )     (261,174 )     (61,239 )
 
                 
 
                       
Net increase (decrease) in cash and cash equivalents
    126       (85,363 )     (5,347 )
 
                 
 
                       
Cash and cash equivalents at beginning of year
    11       85,374       90,721  
 
                 
 
                       
Cash and cash equivalents at end of year
  $ 137     $ 11     $ 85,374  
 
                 
 
(a)   Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

139


 

PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II — RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)
                                         
Column A   Column B   Column C   Column D   Column E
            Additions            
    Balance at   Charged to   Charged           Balance
    beginning   cost and   to other           at end of
Description   of period   expenses   accounts   Deductions   period
Reserve for uncollectibles:
                                       
2007
  $ 5,597     $ 4,130     $     $ 4,945     $ 4,782  
2006
    4,979       4,096             3,478       5,597  
2005
    4,896       2,638             2,555       4,979  

140


 

ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II — RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)
                                         
Column A   Column B   Column C   Column D   Column E
            Additions            
    Balance at   Charged to   Charged           Balance
    beginning   cost and   to other           at end of
Description   of period   expenses   accounts   Deductions   period
Reserve for uncollectibles:
                                       
2007
  $ 4,223     $ 5,059     $     $ 5,018     $ 4,264  
2006
    3,568       4,096             3,441       4,223  
2005
    3,444       2,638             2,514       3,568  

141


 

ITEM 9.01 FINANCIAL STATEMENTS AND EXHIBITS
     (d) Exhibits
             
Exhibit        
No.   Registrant(s)   Description
  12.1     Pinnacle West  
Ratio of Earnings to Fixed Charges
           
 
  12.2     Pinnacle West  
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
           
 
  23.1     Pinnacle West  
Consent of Deloitte & Touche LLP
           
 
  23.2     APS  
Consent of Deloitte & Touche LLP

142


 

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 hereunto duly authorized.
         
  PINNACLE WEST CAPITAL CORPORATION
(Registrant)
 
 
Dated: November 25, 2008  By:   /s/ James R. Hatfield    
    James R. Hatfield
Senior Vice President
 
    and Chief Financial Officer   
 
         
  ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
 
 
Dated: November 25, 2008   By:   /s/ James R. Hatfield    
    James R. Hatfield
Senior Vice President
 
    and Chief Financial Officer   
 

143