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

		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.

TABLE OF CONTENTS

		Page
GLOSSARY			3
Business			5
Selected Financial Data			24
Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Financial Statements and Supplementary Data			59
Financial Statements and Exhibits			142

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

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

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

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:

	•		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.

     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.

     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

     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

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%

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

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

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

     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:

		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,

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

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.

     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 52^nd 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.

     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.

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

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.

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).

     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.

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

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

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.

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

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:

	•		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.

     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	)

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:

	•		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.

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;

	•		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.

     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.

     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:

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

     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.

     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.

     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’

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

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

     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.

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

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.

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):

		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

     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

     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

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’

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.

     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.

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

										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

		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

     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	)