Arizona Public Service 8K Other Events

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 25, 2008


	Exact Name of Registrant as Specified in
	Charter; State of Incorporation;	IRS Employer
Commission File Number	Address and Telephone Number	Identification Number

1-8962	Pinnacle West Capital Corporation	86-0512431
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, AZ 85072-3999
	(602) 250-1000

1-4473	Arizona Public Service Company	86-0011170
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, AZ 85072-3999
	(602) 250-1000

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o		Written communications pursuant to Rule 425 under the Securities Act (17CFR 230.425)

o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

This combined Form 8-K is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 8-K that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

ITEM 8.01. OTHER EVENTS

This Current Report on Form 8-K is limited to the disclosure of the reclassification of financial statements of Pinnacle West Capital Corporation (the “Company” or “Pinnacle West”) and of Arizona Public Service Company (“APS”) to reflect certain reclassifications of marketing and trading assets and liabilities to a net basis of reporting and to reflect reclassifications of certain activities of SunCor Development Company (“SunCor”) to discontinued operations.

This report reflects the impacts of the reclassifications on portions of the following disclosures in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007 (“2007 Form 10-K”):

	•		Item 1. Business;

	•		Item 6. Selected Financial Data;

	•		Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations;

	•		Item 8. Financial Statements and Supplementary Data; and

	•		Item 15. Exhibits and Financial Statement Schedules.

NO ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE OTHER DISCLOSURES EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE RECLASSIFICATIONS DESCRIBED BELOW.

As previously disclosed in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008 (“March 2008 Form 10-Q”), we adopted Financial Accounting Standards Board (“FASB”) Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1) on January 1, 2008. In accordance with this guidance, we elected to offset fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting agreement. FIN 39-1 requires retrospective application for all prior periods presented. Our March 2008 Form 10-Q, our Form 10-Q for the fiscal quarter ended June 30, 2008 (“June 2008 Form 10-Q”), and our Form 10-Q for the fiscal quarter ended September 30, 2008 (“September 2008 Form 10-Q”), previously filed with the Securities and Exchange Commission, reflect such reclassifications.

Also, as previously disclosed in our March 2008 Form 10-Q, June 2008 Form 10-Q and September 2008 Form 10-Q, certain activities related to SunCor were required to be reported as discontinued operations in accordance with Statement of Financial Accounting Standards (“SFAS”) 144. Among other guidance, SFAS 144 prescribes accounting for discontinued operations and defines certain activities as discontinued operations. The March 2008 Form 10-Q, June 2008 Form 10-Q and September 2008 Form 10-Q reflect reclassifications related to certain SunCor discontinued activities for 2007.

This Current Report on Form 8-K provides updated information to substantially conform the 2007 Form 10-K to the presentation reported in our March 2008 Form 10-Q, June 2008 Form 10-Q and September 2008 Form 10-Q.

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


¹		As of January 26, 2008, nuclear capacity increased to 1,147,122 kW, reflecting completion of the steam generator replacement program.

Coal Fueled Generating Facilities

Four Corners– Four Corners is a coal-fired power plant located in the northwestern corner of New Mexico. APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units 4 and 5. APS purchases all of Four Corners’ coal requirements from a supplier

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


(a)		The amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually. Effective June 16, 2007, the seller, Salt River


		Project, reduced the capacity available to APS by 150 MW. Additionally, Salt River Project has elected to cancel this contract effective June 15, 2010.

(b)		This is a seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and APS returns electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2007, APS received 571,342 MWh of energy under the capacity exchange. Additionally, under a supplemental energy sales agreement, APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2007, PacifiCorp received offers of 1,093,175 MWh and purchased 174,340 MWh.

APS continually assesses its need for additional capacity resources to assure system reliability. APS remains committed to seeking proposals from the competitive wholesale market for filling its future resource needs, including renewable resource capacity.

Reserve Margin

APS’ 2007 peak one-hour demand on its electric system was recorded on August 13, 2007 at 7,545,100 kW, compared with the 2006 peak of 7,652,000 kW recorded on July 21, 2006. Taking into account additional capacity then available to APS under long-term purchased power contracts as well as APS generating capacity, APS had capacity of 6,783,000 kW to meet system demand on August 13, 2007, for an installed reserve margin of negative 11.3%. The power actually available to APS from its resources fluctuates from time to time due in part to planned and unplanned plant and transmission outages and technical problems. The available capacity from sources actually operable at the time of the 2007 peak amounted to 5,839,000 kW, for a margin of a negative 33.5%. Firm purchases totaling 3,484,000 kW, including short-term seasonal purchases and unit-contingent purchases, were in place at the time of the peak, ensuring the ability to meet the load requirement with an actual reserve margin of 10.1%.

Transmission and Distribution Facilities

APS’ transmission facilities consist of approximately 5,759 pole miles of overhead lines and approximately 45 miles of underground lines, 5,535 miles of which are located in Arizona. APS’ distribution facilities consist of approximately 12,471 miles of overhead lines and approximately 16,210 miles of underground primary cable, all of which are located in Arizona. APS shares ownership of some of its transmission facilities with other companies. The following table shows APS’ jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2007:


	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 RulesOn 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.

MercuryOn 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 PlanIn 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.

SuperfundSuperfund 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 SitesAPS 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


(a)		Includes regulatory disallowance of $8 million after tax in 2007 and $84 million after tax in 2005. See Note 3.

(b)		Amounts primarily related to Silverhawk and SunCor discontinued operations. See Note 22.

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


(a)		Includes an $84 million after-tax regulatory disallowance of plant costs in 2005 in accordance with APS’ 2003 general retail rate case settlement.

(b)		Includes activities related to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.

(c)		Primarily relates to sales of commercial properties.

(d)		See Note 22.

PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS

2007 Compared with 2006

Our consolidated net income for 2007 was $307 million compared with $327 million for 2006. The current period includes income from discontinued operations of $9 million related to sales of commercial properties by SunCor and a loss from discontinued operations of $3 million related to an APSES project. The prior year includes income from discontinued operations of $10 million related to sales of commercial properties by SunCor. Income from continuing operations decreased $16 million in the year-to-year comparison and is reflected in the segments as follows:

	•		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


(a)		Includes $185 million in 2005 for the acquisition of the Sundance Plant.

(b)		Primarily information systems and facilities projects.

(c)		Consists primarily of capital expenditures for residential, land development and retail and office building construction reflected in “Real estate investments” and “Capital expenditures” on the Consolidated Statements of Cash Flows.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. In addition, these amounts do not include any impacts from the recent changes in the line extension policy (see Note 3). Major transmission projects are driven by regional customer growth.

Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Installation of new steam generators in Palo Verde Unit 3 was completed in the fourth quarter of 2007 at an approximate cost of $70 million (APS’ share), which completed the steam generator replacement program for all three units. Environmental expenditures are estimated at approximately $70 million to $120 million per year for 2008, 2009 and 2010. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require additional environmental expenditures. (See “Business of Arizona Public Service Company — Environmental Matters — Regional Haze Rules” in Item 1.) Generation also includes nuclear fuel expenditures of approximately $90 million to $120 million per year for 2008, 2009 and 2010.

Capital expenditures will be funded with internally generated cash and/or external financings, which may include issuances of long-term debt and Pinnacle West common stock.

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 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


(a)		Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.

Off-Balance Sheet Arrangements

In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).

APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2007, APS would have been required to assume approximately $194 million of debt and pay the equity participants approximately $170 million.

Guarantees and Letters of Credit

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 21 for additional information regarding guarantees and letters of credit.

Contractual Obligations

The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2007 (dollars in millions):


			2009-		2011-
	2008		2010		2012		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	158	$	537	$	1,038	$	3,135	$	4,868
SunCor		173		78		2		2		255
Pinnacle West		10		21		177		—		208

Total long-term debt payments, including interest		341		636		1,217		3,137		5,331

Short-term debt payments, including interest (b)		342		—		—		—		342
Purchased power and fuel commitments (c)		418		651		434		1,584		3,087
Operating lease payments		79		148		133		195		555
Nuclear decommissioning funding requirements		21		46		49		210		326
Purchase obligations (d)		99		29		2		91		221
Uncertain tax positions		203		12		—		—		215

Total contractual commitments	$	1,503	$	1,522	$	1,835	$	5,217	$	10,077


(a)		The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using the rates at December 31, 2007 (see Note 6).

(b)		The short-term debt is primarily related to APS bank borrowings under its revolving line of credit and commercial paper at Pinnacle West (see Note 5).

(c)		Our purchased power and fuel commitments include purchases of coal, electricity, natural gas and nuclear fuel (see Note 11).

(d)		These contractual obligations include commitments for capital expenditures and other obligations.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

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


(a)		Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2007 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2007 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):


	Increase (Decrease)
	Impact on Other			Impact on Other
	Postretirement Benefit			Postretirement
Actuarial Assumption (a)	Obligation			Benefit Expense
Discount rate:
Increase 1%	$	(90	)	$	(4	)
Decrease 1%		105			5
Health care cost trend rate (b):
Increase 1%		94			7
Decrease 1%		(76	)		(5	)
Expected long-term rate of return on plan assets — pretax:
Increase 1%		—			(2	)
Decrease 1%		—			2


(a)		Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

(b)		This assumes a 1% change in the initial and ultimate health care cost trend rate.

See Note 8 for further details about our pension and other postretirement benefit plans.

Derivative Accounting

Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we

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

GeneralElectric 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 ProceedingsOur 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 CostsFuel 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 GrowthThe 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.

WeatherIn 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 MarketOur 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 ExpensesOperations 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 ExpensesDepreciation 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 TaxesTaxes 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 ExpenseInterest 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 CompetitionAlthough 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.

SubsidiariesSunCor’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.

GeneralOur 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


(a)		The decreases in mark-to-market recorded in OCI are due primarily to decreases in forward natural gas prices.

The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2007 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” for more discussion of our valuation methods.


																Total
														Years		fair
Source of Fair Value	2008			2009			2010			2011		2012		thereafter		value
Prices actively quoted	$	(12	)	$	10		$	14		$	2	$	—	$	—	$	14
Prices provided by other external sources		(4	)		(16	)		1			4		3		—		(12	)
Prices based on models and other valuation methods		12			15			(1	)		—		2		10		38

Total by maturity	$	(4	)	$	9		$	14		$	6	$	5	$	10	$	40

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2007 and 2006 (dollars in millions).


	December 31, 2007					December 31, 2006
	Gain (Loss)					Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings
Electricity	$	3	$	(3	)	$	—	$	—
Natural gas		4		(4	)		—		—
Regulatory asset (liability) or OCI (a)
Electricity		45		(45	)		38		(38	)
Natural gas		85		(85	)		80		(80	)

Total	$	137	$	(137	)	$	118	$	(118	)


(a)		These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 1, “Derivative Accounting” for a discussion of our credit valuation adjustment policy. See Note 18 for further discussion of credit risk.

ARIZONA PUBLIC SERVICE COMPANY — RESULTS OF OPERATIONS

Regulatory Matters

See “Pinnacle West Consolidated — Results of Operations — Regulatory Matters” above for information about the ACC’s order in APS’ general retail rate case and the PSA.

2007 Compared with 2006

Our net income for 2007 was $284 million compared with $270 million for 2006. APS’ net income increased approximately $14 million primarily due to higher retail sales related to customer growth; the effects of weather on retail sales; and impacts of the retail rate increase. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs (including increased maintenance and overhauls and the Palo Verde performance improvement plan), customer service and other costs; higher depreciation and amortization primarily due to increased plant balances; higher interest expense due to higher debt balances and higher rates; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior year and lower interest income as a result of lower investment balances; and a regulatory disallowance (see Note 3). In addition, higher fuel and purchased power costs related to commodity price increases were partially offset by the deferral of such costs in accordance with the PSA. See Note 3 for further discussion.


	Increase (Decrease)
	Pretax			After Tax
Higher retail sales primarily due to customer growth, excluding weather effects	$	46		$	28
Effects of weather on retail sales		37			23
Impacts of retail rate increase effective July 1, 2007:
Revenue increase related to higher Base Fuel Rate		185			113
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(171	)		(104	)
Non-fuel rate increase		6			4
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs related to increased commodity prices		(121	)		(74	)

Increased deferred fuel and purchased power costs related to increased prices		115			70
Mark-to-market fuel and purchased power costs, net of related deferred fuel and purchased power costs		18			11
Regulatory disallowance (see Note 3)		(14	)		(8	)
Operations and maintenance increases primarily due to:
Increased generation costs, including increased maintenance and overhauls and Palo Verde performance improvement plan		(25	)		(15	)
Customer service and other costs		(19	)		(11	)
Higher depreciation and amortization primarily due to increased plant balances		(12	)		(7	)
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in prior year		(7	)		(4	)
Income tax benefits resolved in 2007 related to prior years		—			11
Income tax credits resolved in 2006 related to prior years		—			(11	)
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates		(7	)		(4	)
Lower marketing and trading contribution primarily due to lower mark-to-market gains because of changes in forward prices		(7	)		(4	)
Other miscellaneous items, net		2			(4	)

Increase in net income	$	26		$	14

Electric operating revenues were $278 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:

	•		a $191 million increase in retail revenues due to a rate increase effective July 1, 2007;

	•		a $60 million increase in retail revenues primarily related to customer growth, excluding weather effects;

	•		a $50 million increase in retail revenues due to the effects of weather;

	•		a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;

	•		a $35 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 3); and

	•		a $9 million net increase due to miscellaneous factors.

2006 Compared with 2005

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

Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2006 compared with the year ended December 31, 2005 are contained in the following table (dollars in millions):


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

Increase in net income	$	140		$	100

Electric operating revenues were $388 million higher for 2006 compared with the prior year primarily as a result of:

	•		a $265 million increase in revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense;

	•		a $124 million increase in retail revenues related to customer growth, excluding weather effects; and

	•		a $1 million decrease due to miscellaneous factors.

LIQUIDITY AND CAPITAL RESOURCES — ARIZONA PUBLIC SERVICE COMPANY

Operating Cash Flows

Net cash provided by operating activities was $766 million for 2007, compared with $394 million for 2006, an increase in net cash flow of $372 million. This change was primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.

Net cash provided by operating activities was $394 million for 2006, compared with $722 million for 2005, a decrease in net cash flow of $328 million. This change was primarily due to an increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.

Investing Cash Flows

Net cash used for investing activities was $881 million for 2007, compared with $714 million for 2006, a decrease in net cash flow of $167 million.

This cash flow decrease was primarily due to:

•

An increase of $239 million in cash used for capital expenditures and allowance for borrowed funds used during construction (see table and discussion above).

The cash flow decrease was partially offset by:

	•		A decrease of $65 million in cash invested in securities; and

	•		A net increase of $7 million due to miscellaneous factors.

Net cash used for investing activities was $714 million for 2006, compared with $645 million for 2005, a decrease in net cash flow of $69 million.

This cash flow decrease was primarily due to:

	•		A decrease of $500 million related to repayment in 2005 by PWEC of a loan;

	•		An increase of $214 million in cash invested in securities; and

	•		A net decrease of $1 million due to miscellaneous factors.

The cash flow decreases were partially offset by:

•

Less cash used for capital expenditures (including, in 2005, the acquisition of the PWEC Dedicated Assets and the Sundance Plant) and allowance for borrowed funds used during construction of $646 million (see table and discussion above).

Financing Cash Flows

Net cash provided by financing activities was $86 million for 2007, compared with $352 million for 2006, a decrease in net cash flow of $266 million.

The cash flow decrease was primarily due to:

	•		A decrease of $311 million in net new long-term debt (issuances net of redemptions and refinancing) to fund APS’ construction program and for general corporate purposes; and

	•		A decrease of $173 million due to decreased equity infusions from Pinnacle West.

The cash flow decreases were partially offset by:

•

A net increase of $218 million in short-term borrowings to fund day-to-day operations and liquidity needs.

Net cash provided by financing activities was $352 million for 2006, compared with net cash used for financing activities in 2005 of $76 million, an increase in net cash flow of $428 million.

This cash flow increase was primarily due to:

•

An increase of $466 million in net new long-term debt (issuances net of redemptions and refinancings) in order to fund our construction program and for other general corporate purposes.

This cash flow increase was partially offset by:

	•		A decrease of $37 million due to decreased equity infusions from Pinnacle West; and

	•		A net decrease of $1 million due to miscellaneous factors.

Liquidity

For additional discussion see “Liquidity and Capital Resources — Pinnacle West Consolidated.”

Contractual Obligations

The following table summarizes contractual requirements for APS as of December 31, 2007 (dollars in millions):


			2009-		2011-		There-
	2008		2010		2012		after		Total
Long-term debt payments, including interest (a)	$	158	$	537	$	1,038	$	3,135	$	4,868
Short-term debt payments, including interest		219		—		—		—		219
Purchased power and fuel commitments (b)		375		651		422		1,584		3,032
Operating lease payments		72		136		124		177		509
Nuclear decommissioning funding requirements		21		46		49		210		326
Purchase obligations (c)		99		29		2		91		221
Uncertain tax positions		198		12		—		—		210

Total contractual commitments	$	1,142	$	1,411	$	1,635	$	5,197	$	9,385


(a)		The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by the rates at December 31, 2007 (see Note 6).

(b)		APS’ purchased power and fuel commitments include purchases of coal, electricity, natural gas, and nuclear fuel (see Note 11).

(c)		These contractual obligations include commitments for capital expenditures and other obligations.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE


	Page
Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)		60
Report of Independent Registered Public Accounting Firm		61
Pinnacle West Consolidated Statements of Income for 2007, 2006 and 2005		63
Pinnacle West Consolidated Balance Sheets as of December 31, 2007 and 2006		64
Pinnacle West Consolidated Statements of Cash Flows for 2007, 2006 and 2005		66
Pinnacle West Consolidated Statements of Changes in Common Stock Equity for 2007, 2006 and 2005		67
Notes to Pinnacle West’s Consolidated Financial Statements		68

Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)		118
Report of Independent Registered Public Accounting Firm		119
APS Statements of Income for 2007, 2006 and 2005		121
APS Balance Sheets as of December 31, 2007 and 2006		122
APS Statements of Cash Flows for 2007, 2006 and 2005		124
APS Statements of Changes in Common Stock Equity for 2007, 2006 and 2005		125
Supplemental Notes to APS’ Financial Statements		127

Financial Statement Schedules for 2007, 2006 and 2005
Pinnacle West Schedule I – Condensed Statements of Income for 2007, 2006 and 2005		137
Pinnacle West Schedule I – Condensed Balance Sheets as of December 31, 2007 and 2006		138
Pinnacle West Schedule I – Condensed Statements of Cash Flows for 2007, 2006 and 2005		139
Pinnacle West Schedule II – Reserve for Uncollectibles for 2007, 2006 and 2005		140
APS Schedule II – Reserve for Uncollectibles for 2007, 2006 and 2005		141

See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.

MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)

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

February 27, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

As reflected in the consolidated statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Planseffective December 31, 2006.

As discussed in Note 23, the Company adopted the provisions of FASB Staff Position No. FIN 39-1. Also, as discussed in Note 22, SunCor entered into an agreement in the first quarter of 2008 to sell certain commercial properties and, accordingly, reclassified the related operating results to discontinued operations on the 2007 Consolidated Statement of Income in accordance with SFAS 144.

/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP

Phoenix, Arizona
February 27, 2008
(November 25, 2008 as to (1) the effects of the adoption of FASB Staff Position No. FIN 39-1 as described in Note 23, and (2) the effects of discontinued operations related to SunCor as described in Note 22).

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)


	Year Ended December 31,
	2007			2006			2005
OPERATING REVENUES
Regulated electricity segment	$	2,918,163		$	2,635,036		$	2,237,145
Real estate segment		212,586			399,798			338,031
Marketing and trading		342,371			330,742			351,558
Other revenues		48,018			36,172			61,221

Total		3,521,138			3,401,748			2,987,955

OPERATING EXPENSES
Regulated electricity segment fuel andpurchased power		1,140,923			960,649			595,141
Real estate segment operations		192,972			324,861			278,366
Marketing and trading fuel andpurchased power		294,236			290,637			293,091
Operations and maintenance		734,705			691,277			635,827
Depreciation and amortization		372,128			358,644			347,652
Taxes other than income taxes		128,218			128,395			132,040
Other expenses		38,925			28,415			51,987
Regulatory disallowance (Note 3)		—			—			138,562

Total		2,902,107			2,782,878			2,472,666

OPERATING INCOME		619,031			618,870			515,289

OTHER
Allowance for equity funds used during construction		21,195			14,312			11,191
Other income (Note 19)		24,694			44,016			23,360
Other expense (Note 19)		(25,883	)		(27,800	)		(26,716	)

Total		20,006			30,528			7,835

INTEREST EXPENSE
Interest charges		208,521			196,826			185,087
Capitalized interest		(23,063	)		(20,989	)		(12,018	)

Total		185,458			175,837			173,069

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		453,579			473,561			350,055
INCOME TAXES (Note 4)		152,447			156,418			126,892

INCOME FROM CONTINUING OPERATIONS		301,132			317,143			223,163
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $4,045, $6,570 and ($29,797)		6,011			10,112			(46,896	)

NET INCOME	$	307,143		$	327,255		$	176,267

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		100,256			99,417			96,484
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		100,835			100,010			96,590
EARNINGS PER WEIGHTED — AVERAGE COMMON SHARE OUTSTANDING

Income from continuing operations — basic	$	3.00		$	3.19		$	2.31
Net income — basic		3.06			3.29			1.83
Income from continuing operations — diluted		2.99			3.17			2.31
Net income — diluted		3.05			3.27			1.82
DIVIDENDS DECLARED PER SHARE	$	2.10		$	2.025		$	1.925

See Notes to Pinnacle West’s Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)


	December 31,
	2007			2006
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	56,321		$	87,210
Investment in debt securities		—			32,700
Customer and other receivables		456,007			501,628
Allowance for doubtful accounts		(4,782	)		(5,597	)
Materials and supplies (at average cost)		149,759			125,802
Fossil fuel (at average cost)		27,792			21,973
Deferred income taxes (Note 4)		31,510			982
Assets from risk management and trading activities(Note 18)		57,605			112,547
Home inventory (Note 1)		98,729			41,846
Other current assets		33,988			17,090

Total current assets		906,929			936,181


INVESTMENTS AND OTHER ASSETS
Real estate investments — net (Notes 1 and 6)		532,600			526,008
Assets from long-term risk management and trading activities (Note 18)		48,928			67,649
Decommissioning trust accounts (Note 12)		379,347			343,771
Other assets		117,941			111,388

Total investments and other assets		1,078,816			1,048,816


PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
Plant in service and held for future use		11,640,739			11,154,919
Less accumulated depreciation and amortization		4,004,944			3,797,475

Net		7,635,795			7,357,444
Construction work in progress		625,577			368,284
Intangible assets, net of accumulated amortization of $252,122 and $218,836		105,746			96,100
Nuclear fuel, net of accumulated amortization of $68,375 and $50,741		69,271			60,100

Total property, plant and equipment		8,436,389			7,881,928


DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Notes 1, 3 and 4)		110,928			160,268
Other regulatory assets (Notes 1, 3 and 4)		514,353			686,016
Other deferred debits		114,794			104,691

Total deferred debits		740,075			950,975


TOTAL ASSETS	$	11,162,209		$	10,817,900

See Notes to Pinnacle West’s Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)


	December 31,
	2007			2006
LIABILITIES AND COMMON STOCK EQUITY

CURRENT LIABILITIES
Accounts payable	$	323,346		$	346,047
Accrued taxes		269,628			263,935
Accrued interest		39,836			48,746
Short-term borrowings (Note 5)		340,661			35,750
Current maturities of long-term debt (Note 6)		163,773			1,596
Customer deposits		80,010			70,168
Liabilities from risk management and trading activities (Note 18)		24,510			77,064
Other current liabilities		102,685			80,032

Total current liabilities		1,344,449			923,338


LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)		3,127,125			3,232,633


DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)		1,243,743			1,225,798
Regulatory liabilities (Notes 1, 3 and 4)		642,564			635,431
Liability for asset retirements (Note 12)		281,903			268,389
Liabilities for pension and other postretirement benefits (Note 8)		504,603			588,852
Liabilities from risk management and trading activities (Note 18)		4,701			68,349
Unamortized gain — sale of utility plant (Note 9)		36,606			41,182
Other		444,904			387,812

Total deferred credits and other		3,159,024			3,215,813


COMMITMENTS AND CONTINGENCIES (SEE NOTES)

COMMON STOCK EQUITY (Note 7)
Common stock, no par value; authorized 150,000,000 shares; issued 100,525,470 at end of 2007 and 99,961,066 at end of 2006		2,135,787			2,114,550
Treasury stock at cost; 39,505 shares at end of 2007 and 2,419 shares at end of 2006		(2,054	)		(449	)

Total common stock		2,133,733			2,114,101

Accumulated other comprehensive income (loss):
Pension and other postretirement benefits (Note 8)		(39,336	)		(19,263	)
Derivative instruments		23,473			31,531

Total accumulated other comprehensive income		(15,863	)		12,268

Retained earnings		1,413,741			1,319,747

Total common stock equity		3,531,611			3,446,116


TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	11,162,209		$	10,817,900

See Notes to Pinnacle West’s Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)


	Year Ended December 31,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	307,143		$	327,255		$	176,267
Adjustments to reconcile net income to net cash provided by
operating activities:
Silverhawk impairment loss		—			—			91,025
Regulatory disallowance		—			—			138,562
Depreciation and amortization including nuclear fuel		403,896			386,760			381,604
Deferred fuel and purchased power		(196,136	)		(252,849	)		(172,756	)
Deferred fuel and purchased power amortization		231,106			265,337			—
Deferred fuel and purchased power disallowance		14,370			—			—
Allowance for equity funds used during construction		(21,195	)		(14,312	)		(11,191	)
Deferred income taxes		(58,027	)		27,738			(23,806	)
Change in mark-to-market valuations		17,579			28,464			(11,670	)
Changes in current assets and liabilities:
Customer and other receivables		62,850			9,189			(38,763	)
Materials, supplies and fossil fuel		(29,776	)		(9,094	)		(16,836	)
Other current assets		(10,040	)		(890	)		(1,395	)
Accounts payable		(42,004	)		(46,055	)		(6,392	)
Home inventory		(56,883	)		11,563			(21,400	)
Accrued taxes		20,764			(22,329	)		43,624
Other current liabilities		22,657			21,763			1,567
Proceeds from the sale of real estate assets		82,521			34,990			16,218
Real estate investments		(121,316	)		(126,229	)		(88,055	)
Change in margin and collateral accounts — assets		(37,371	)		(249,792	)		251,925
Change in margin and collateral accounts — liabilities		19,284			(46,444	)		(17,012	)
Changes in unrecognized tax benefits		25,178			—			—
Change in other long-term assets		(23,826	)		17,541			(35,793	)
Change in other long-term liabilities		47,162			30,896			74,573

Net cash flow provided by operating activities		657,936			393,502			730,296


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(918,581	)		(737,779	)		(633,532	)
Capitalized interest		(23,063	)		(20,990	)		(12,018	)
Purchase of Sundance Plant		—			—			(185,046	)
Proceeds from the sale of Silverhawk		—			207,620			—
Purchases of investment securities		(36,525	)		(1,439,404	)		(2,962,278	)
Proceeds from sale of investment securities		69,225			1,406,704			3,143,481
Proceeds from nuclear decommissioning trust sales		259,026			254,651			186,215
Investment in nuclear decommissioning trust		(279,768	)		(275,393	)		(204,633	)
Proceeds from sale of real estate investments		58,139			39,621			82,719
Other		(1,807	)		(3,763	)		—

Net cash flow used for investing activities		(873,354	)		(568,733	)		(585,092	)


CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		230,571			757,636			1,088,815
Repayment of long-term debt		(162,060	)		(527,864	)		(1,288,034	)
Short-term borrowings and payments — net		304,911			9,911			(46,413	)
Dividends paid on common stock		(210,473	)		(201,220	)		(186,677	)
Common stock equity issuance		24,089			39,548			298,168
Other		(2,509	)		30,427			(20,426	)

Net cash flow provided by (used for) financing activities		184,529			108,438			(154,567	)


NET DECREASE IN CASH AND CASH EQUIVALENTS		(30,889	)		(66,793	)		(9,363	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		87,210			154,003			163,366


CASH AND CASH EQUIVALENTS AT END OF YEAR	$	56,321		$	87,210		$	154,003

Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid, net of refunds	$	204,643		$	157,245		$	86,711
Interest paid, net of amounts capitalized	$	193,533		$	153,503		$	181,975

See Notes to Pinnacle West’s Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)


	Year Ended December 31,
	2007			2006			2005
COMMON STOCK (Note 7)
Balance at beginning of year	$	2,114,550		$	2,067,377		$	1,769,047
Issuance of common stock		24,089			39,420			298,330
Other		(2,852	)		7,753			—

Balance at end of year		2,135,787			2,114,550			2,067,377


TREASURY STOCK (Note 7)
Balance at beginning of year		(449	)		(1,245	)		(428	)
Purchase of treasury stock		(1,964	)		(229	)		(1,601	)
Reissuance of treasury stock used for stock compensation, net		359			1,025			784

Balance at end of year		(2,054	)		(449	)		(1,245	)


RETAINED EARNINGS
Balance at beginning of year		1,319,747			1,193,712			1,204,122
Net income		307,143			327,255			176,267
Common stock dividends		(210,473	)		(201,220	)		(186,677	)
Cumulative effect of change in accounting for income taxes (Note 4)		(2,676	)		—			—

Balance at end of year		1,413,741			1,319,747			1,193,712


ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		12,268			165,120			(22,545	)
Pension and other postretirement benefits (Note 8):
Unrealized actuarial loss, net of tax benefit of ($13,573)		(21,976	)		—			—
Prior service cost, net of tax benefit of ($495)		(769	)		—			—
Amortization to income:
Actuarial loss, net of tax expense of $1,670		2,214			—			—
Prior service cost, net of tax expense of $252		391			—			—
Transition obligation, net of tax expense of $43		67			—			—
Minimum pension liability adjustment, net of tax expense (benefit) of $28,425 and ($9,526)		—			44,086			(15,489	)
Adjustment to reflect a change in accounting, net of tax expense of $22,412		—			33,928			—
Derivative instruments:
Net unrealized gain (loss), net of tax expense (benefit) of ($414), ($137,606) and $179,927		(785	)		(214,777	)		281,019
Reclassification of net realized gain to income, net of tax benefit of ($4,679), ($10,308) and ($50,056)		(7,273	)		(16,089	)		(77,865	)

Balance at end of year		(15,863	)		12,268			165,120


TOTAL COMMON STOCK EQUITY	$	3,531,611		$	3,446,116		$	3,424,964


COMPREHENSIVE INCOME
Net income	$	307,143		$	327,255		$	176,267
Other comprehensive income (loss)		(28,131	)		(186,780	)		187,665

Comprehensive income	$	279,012		$	140,475		$	363,932

See Notes to Pinnacle West’s Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Consolidation and Nature of Operations

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado, Pinnacle West Marketing & Trading, and Pinnacle West Energy (dissolved as of August 31, 2006). Significant intercompany accounts and transactions between the consolidated companies have been eliminated.

APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. APSES provides energy-related projects and competitive commodity energy to commercial and industrial retail customers in competitive markets in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in early 2007. These operations were previously conducted by a division of Pinnacle West through the end of 2006.

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas and emissions allowances. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if certain hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). To the extent the amounts that would otherwise be recognized in income are eligible to be recovered through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

Under fair value (mark-to-market) accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, as current or long-term assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets.

We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted.

When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers, which we convert into monthly prices using historical relationships.

For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.

For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.

The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.

See Note 2 for information about a new accounting standard on fair value measurements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

See Note 18 for additional information about our derivative and energy trading accounting policies.

Regulatory Accounting

APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

A major component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery or refund 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates, subject to specified parameters.

The detail of regulatory assets is as follows (dollars in millions):


	December 31,
	2007		2006
Pension and other postretirement benefits	$	338	$	473
Deferred fuel and purchased power (a) (Note 3)		111		160
Regulatory asset for deferred income taxes		40		27
Deferred compensation		30		28
Competition rules compliance charge (a)		25		34
Loss on reacquired debt (b)		16		17
Deferred fuel and purchased power – mark-to-market		7		62
Other		58		45

Total regulatory assets (c)	$	625	$	846


(a)		Subject to a carrying charge.

(b)		See “Reacquired Debt Costs” below.

(c)		There are no regulatory assets for which regulators have allowed recovery of costs but not allowed a return by exclusion from rate base.

The detail of regulatory liabilities is as follows (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	December 31,
	2007		2006
Removal costs (a)	$	392	$	387
Regulatory liability related to asset retirement obligations		153		133
Tax benefit of Medicare subsidy		35		50
Deferred gains on utility property		20		20
Deferred interest income (b)		13		18
Regulatory liability for deferred income taxes		6		11
Other		24		16

Total regulatory liabilities	$	643	$	635


(a)		In accordance with SFAS No. 71, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.

(b)		Subject to a carrying charge.

Utility Plant and Depreciation

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:

	•		material and labor;

	•		contractor costs;

	•		capitalized leases;

	•		construction overhead costs (where applicable); and

	•		capitalized interest or an allowance for funds used during construction.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.

APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated under SFAS No. 143 “Accounting for Asset Obligations,” as interpreted by FIN 47. APS believes it can recover in regulated rates the costs calculated in accordance with SFAS No. 143.

We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2007 were as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	•		Fossil plant – 17 years;

	•		Nuclear plant – 17 years;

	•		Other generation – 29 years;

	•		Transmission – 43 years;

	•		Distribution – 33 years; and

	•		Other – 6 years.

For the years 2005 through 2007, the depreciation rates ranged from a low of 1.11% to a high of 12.46%. The weighted-average rate was 3.11% for 2007, 3.14 % for 2006 and 3.0% for 2005. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years.

Investments

El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).

Our investments in the nuclear decommissioning trust fund are accounted for in accordance with EITF 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” See Note 12 for more information on these investments.

Capitalized Interest

Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. The rate used to calculate capitalized interest was a composite rate of 5.8% for 2007, 6.8% for 2006 and 5.7% for 2005. Capitalized interest ceases when construction is complete.

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. APS’ allowance for borrowed funds is included in capitalized interest on the Consolidated Financial Statements. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

AFUDC was calculated by using a composite rate of 8.2% for 2007, 8.0% for 2006 and 7.7% for 2005. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Electric Revenues

We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Beginning April 2005, in accordance with a 2005 ACC order, we also exclude city franchise fees from both electric revenues and operating expenses.

Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and purchased power and fuel costs.

All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis.

Real Estate Revenues

SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed under the percentage of completion method per SFAS No. 66, “Accounting for Sales of Real Estate.” SunCor recognizes income only after the asset title has passed. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. In addition, see Note 22 – Discontinued Operations.

Real Estate Investments

Real estate investments primarily include SunCor’s land, home inventory, commercial property and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except that, to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Homes under construction classified as “real estate investments” on the Consolidated Balance Sheets are transferred to “home inventory” upon completion of construction with the expectation that they will be sold in a timely manner. In previous years, “home inventory” was classified as “other current assets” on the Consolidated Balance Sheets. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. In addition, see Note 22 – Discontinued Operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash and Cash Equivalents

We consider all highly liquid investments with a maturity of three months or less at acquisition to be cash equivalents.

Investments in auction rate securities have interest rates that are reset on a short-term basis; however, the underlying contract maturity dates extend beyond three months. We classify the investments in auction rate securities as investment in debt securities on our Consolidated Balance Sheets.

Nuclear Fuel

APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal and Note 12 for information on nuclear decommissioning costs.

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes” and FIN 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the most probable resolution of all known and measurable tax exposures. See Note 4.

Reacquired Debt Costs

APS defers gains and losses incurred upon early retirement of debt. These costs are amortized equally on a monthly basis over the remaining life of the original debt consistent with its ratemaking treatment.

Stock-based Compensation

Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and some of our subsidiaries. Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective application method. Because the fair value recognition provisions of both SFAS No. 123 and SFAS No. 123(R) are materially

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

consistent with respect to our stock-based compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements. See Note 16.

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. Amortization expense was $37 million in 2007, $39 million in 2006 and $33 million in 2005. Estimated amortization expense on existing intangible assets over the next five years is $29 million in 2008, $20 million in 2009, $19 million in 2010, $12 million in 2011 and $10 million in 2012. At December 31, 2007, the weighted average remaining amortization period for intangible assets was 5 years.

2. New Accounting Standards

See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007.

3. Regulatory Matters

Retail Rate Order

Retail Rate IncreaseOn June 28, 2007, the ACC issued an order (the “Retail Rate Order”) in a general retail rate case that APS filed in late 2005. The Retail Rate Order approved a $322 million increase in APS’ annual retail base revenues, effective July 1, 2007, which included a $315 million fuel-related increase and a $7 million non-fuel related increase. The Retail Rate Order also authorized APS’ recovery of approximately $34 million of 2005 Deferrals through a temporary PSA surcharge over a twelve-month period beginning July 1, 2007. The ACC disallowed approximately $14 million of 2005 Deferrals because it found the Palo Verde outage costs giving rise to those amounts resulted from APS’ imprudence.

PSA ModificationsThe Retail Rate Order modified the PSA in various respects, effective July 1, 2007. The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case,

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. As modified by the Retail Rate Order, the PSA is subject to specified parameters and procedures, including the following:

	•		APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate (currently $0.0325 per kWh);

	•		under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchase power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate;

	•		an adjustment is made annually each February 1^st and goes into effect automatically unless suspended by the ACC;

	•		the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which will be reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

	•		the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) an “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component;

	•		amounts to be recovered or refunded through the sum of the PSA components discussed in the preceding bullet point are limited to a maximum plus or minus $0.004 per kWh change in the PSA rate in any PSA Year; and

	•		the PSA adjustor that took effect on February 1, 2007 ($0.004 per kWh), and that was scheduled to expire on January 31, 2008, will remain in effect as long as necessary after January 31, 2008 to collect $46 million of 2007 fuel and purchased power costs deferred as a result of the mid-2007 implementation of the new Base Fuel Rate.

PSA Balance

The following table shows the changes in the deferred fuel and purchased power regulatory asset for the years ended December 31, 2007 and 2006 (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2007			2006
Beginning balance	$	160		$	173
Deferred fuel and purchased power costs-current period		189			244
Regulatory disallowance		(14	)		—
Interest on deferred fuel and purchased power		7			8
Amounts recovered through revenues		(231	)		(265	)

Ending balance	$	111		$	160

The PSA rate for the PSA Year beginning February 1, 2008 was set at the maximum $0.004 per kWh. Any uncollected deferrals during the 2008 PSA Year resulting from this limit will be included in the Historical Component of the PSA rate for the PSA Year beginning February 1, 2009.

2006 Deferrals

In May 2006, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde outage costs. APS recorded approximately $79 million of 2006 Deferrals, virtually all of which were associated with a Unit 1 vibration issue. On October 4, 2007, the ACC staff filed a report with the ACC that concluded that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that these costs, which have been fully recovered, were prudently incurred.

Line Extension Schedule

The Retail Rate Order required APS to file a revised line extension schedule for ACC approval that would eliminate certain footage and equipment allowances for new or expanded electric service and remove any requirement for economic feasibility analyses used to determine whether or how much of an allowance should be granted. These changes would permit APS to collect, on a current basis, costs related to line extensions.

On October 24, 2007, APS filed a proposed amendment to its line extension schedule, including a proposal to treat line extension payments received as non-refundable other electric revenues. APS proposed to “grandfather” applicants that have executed line extension agreements prior to the effective date of its amended line extension schedule. The ACC Staff issued a recommended order that was consistent with APS’ proposed line extension amendments in all significant respects except for the authorized accounting treatment. The ACC staff proposed that payments received for new or upgraded service be treated as contributions in aid of construction (“CIAC”), rather than as non-refundable other electric revenues as APS requested. CIAC treatment would result in a positive cash flow that will partially offset capital expenditures, but without any revenue impact. On February 13, 2008, the ACC voted to approve the ACC staff recommended order, with minor modifications.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Rate Requests for Transmission and Ancillary Services

On July 10, 2007, APS submitted a revised Open Access Transmission Tariff filing with the FERC to move from a fixed rate to a formula rate in order to more accurately reflect the costs that APS incurs in providing transmission and ancillary services. The requested formula rate would have resulted in an estimated $37 million increase in annual transmission revenues, effective October 1, 2007. The proposed formula rate would be updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and projected capital expenditures. Approximately $30 million of the requested increase represents charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”).

On September 21, 2007, the FERC issued an order on these proposed revisions to APS’ transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge procedures, which are underway. The proposed rates become effective March 1, 2008, subject to refund based upon the ultimate outcome of proceedings at the FERC on this matter.

On December 31, 2007, APS filed with the ACC an application to increase annual pretax retail revenues by approximately $30 million, effective March 1, 2008, to cover the Retail Transmission Charges authorized by the FERC. This retail rate increase implements an ACC-approved mechanism by which changes in Retail Transmission Charges can be reflected in APS’ retail rates. On February 13, 2008, the ACC voted to approve APS’ request, subject to refund pending final outcome of FERC proceedings on this matter.

Other

On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003. As part of this order, APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was $139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $84 million in 2005.

Federal

FERC Order

On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.

On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ authority to make sales at market-based rates in the APS control area (the “April 17 Order”). The

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.

On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on October 12, 2007. This compliance filing was conditionally accepted by FERC in an order issued January 17, 2008, requiring an additional compliance filing by the Pinnacle West Companies by February 19, 2008.

Based upon an analysis of this matter and preliminary calculations of the refund obligations, at this time neither Pinnacle West nor APS believes that this proceeding will have a material adverse effect on its financial position, results of operations or cash flows.

4. Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.

APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.

As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next six months, we expect that the IRS will finalize its examination of the 2001 return, which will include a settlement on the tax accounting method change. Although the ultimate outcome of this matter cannot currently be predicted, the current status of the examination has resulted in changes in our judgment, which are reflected in the reconciliation of the total amounts of unrecognized tax benefits presented below. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows. We do not expect that there will be any other significant increases or decreases in our unrecognized tax benefits within the next 12 months.

We adopted FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109,” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.

Following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Consolidated Balance Sheets (dollars in thousands):


Total unrecognized tax benefits, January 1, 2007	$	132,691
Additions for tax positions of the current year		—
Additions for tax positions of prior years		65,022
Reductions for tax positions of prior years for:
Changes in judgment		(37,419	)
Settlements with taxing authorities		(2,425	)
Lapses of applicable statute of limitations		—

Total unrecognized tax benefits, December 31, 2007	$	157,869

Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately $5 million of tax positions that, if recognized, would decrease our effective tax rate.

We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of operations as income tax expense. For 2007, the amount of interest recognized in the statement of operations related to unrecognized tax benefits was $3 million.

As of December 31, 2007, the total amount of interest expense recognized in the statement of financial position related to unrecognized tax benefits was $57 million. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

As of December 31, 2007, the tax year ended December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ended prior to December 31, 1999 may remain subject to examination by state taxing authorities.

The components of income tax expense are as follows (dollars in thousands):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Year Ended December 31,
	2007			2006		2005
Current:
Federal	$	183,547		$	110,029	$	107,837
State		30,972			21,507		13,064

Total current		214,519			131,536		120,901

Deferred:
Income from continuing operations		(56,147	)		31,452		11,930
Discontinued operations		(1,880	)		—		(35,736	)

Total deferred		(58,027	)		31,452		(23,806	)

Total income tax expense		156,492			162,988		97,095
Less: income tax expense (benefit) on discontinued operations		4,045			6,570		(29,797	)

Income tax expense — continuing operations	$	152,447		$	156,418	$	126,892

The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):


	Year Ended December 31,
	2007			2006			2005
Federal income tax expense at 35% statutory rate	$	158,753		$	165,746		$	122,519
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		16,964			17,309			11,981
Credits and favorable adjustments related to prior years resolved in current year		(13,205	)		(14,028	)		—
Medicare Subsidy Part-D		(3,236	)		(3,156	)		(2,733	)
Allowance for equity funds used during construction (see Note 1)		(6,899	)		(4,679	)		(3,694	)
Other		70			(4,774	)		(1,181	)

Income tax expense — continuing operations	$	152,447		$	156,418		$	126,892

The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):


	December 31,
	2007			2006
Current asset	$	31,510		$	982
Long-term liability		(1,243,743	)		(1,225,798	)

Accumulated deferred income taxes — net	$	(1,212,233	)	$	(1,224,816	)

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the net deferred income tax liability were as follows (dollars in thousands):


	December 31,
	2007			2006
DEFERRED TAX ASSETS
Risk management and trading activities	$	13,958		$	66,946
Regulatory liabilities:
Asset retirement obligation		214,607			203,846
Federal excess deferred income taxes		11,091			12,714
Tax benefit of Medicare subsidy		11,727			18,214
Other		26,579			27,283
Pension and other postretirement liabilities		211,192			272,484
Deferred gain on Palo Verde Unit 2 sale leaseback		14,408			16,160
Other		112,209			73,811

Total deferred tax assets		615,771			691,458

DEFERRED TAX LIABILITIES
Plant-related		(1,538,183	)		(1,509,812	)
Risk management and trading activities		(29,531	)		(72,755	)
Regulatory assets:
Deferred fuel and purchased power		(43,661	)		(62,889	)
Deferred fuel and purchased power — mark-to-market		(2,782	)		(24,427	)
Pension and other postretirement benefits		(133,120	)		(185,602	)
Other		(80,727	)		(60,789	)

Total deferred tax liabilities		(1,828,004	)		(1,916,274	)

Accumulated deferred income taxes — net	$	(1,212,233	)	$	(1,224,816	)

5. Lines of Credit and Short-Term Borrowings

Pinnacle West had a committed line of credit with various banks totaling $300 million at December 31, 2007 and December 31, 2006, which was available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuance of letters of credit. The current line terminates in December 2010. Pinnacle West had no outstanding borrowings under the lines of credit at December 31, 2007 and December 31, 2006. Pinnacle West had approximately $5 million of letters of credit issued under the line at December 31, 2007 and approximately $4 million of letters of credit issued under the line at December 31, 2006. The commitment fees were 0.15% in 2007 and 2006. Pinnacle West had commercial paper borrowings of $115 million outstanding at December 31, 2007 and $28 million outstanding at December 31, 2006. The weighted average interest rates were 5.73% at December 31, 2007 and 5.625% at December 31, 2006. All Pinnacle West and APS bank lines of credit and commercial paper agreements are unsecured.

APS had two committed lines of credit with various banks totaling $900 million at December 2007 and 2006, all of which were available either to support the issuance of up to $250 million in

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

commercial paper or to be used for bank borrowings, including the issuance of letters of credit. The $400 million line terminates in December 2010 and the $500 million line terminates in September 2011. APS may increase the $500 million line to $600 million if certain conditions are met. The commitment fees for these lines of credit were 0.10% and 0.11% at December 31, 2007 and December 31, 2006. APS had bank borrowings outstanding of $218 million under the $500 million line of credit at December 31, 2007 and no borrowings outstanding at December 31, 2006. The weighted average interest rate was 5.361% at December 31, 2007. APS had approximately $4 million of letters of credit issued under the $400 million line at December 31, 2007 and 2006.

Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.

SunCor had two revolving lines of credit totaling $170 million at December 31, 2007, and December 31, 2006 maturing in October 2008 and December 2008. The commitment fees were 0.125% in 2007 and 2006 for the $150 million line of credit. The commitment fees for the $20 million line of credit were 0.50% in 2007 and 2006. SunCor had $94 million outstanding at December 31, 2007 and $118 million outstanding at December 31, 2006. The weighted-average interest rate was 7.27% at December 31, 2007 and 7.09% at December 31, 2006. Interest was based on LIBOR plus 2.0% for 2007 and 2006. The balance is included in current maturities of long-term debt on the Consolidated Balance Sheets at December 31, 2007 and 2006. SunCor had other short-term loans in the amount of $8 million at December 31, 2007 and $8 million at December 31, 2006. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2007 and 2006.

6. Long-Term Debt

Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2007 and 2006 (dollars in thousands):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Maturity	Interest			December 31,
	Dates (a)	Rates			2007			2006
APS

Pollution control bonds	2024-2034		(b	)	$	565,855		$	565,855
Pollution control bonds with senior notes	2029		5.05	%		90,000			90,000
Unsecured notes	2011		6.375	%		400,000			400,000
Unsecured notes	2012		6.50	%		375,000			375,000
Unsecured notes	2033		5.625	%		200,000			200,000
Unsecured notes	2015		4.650	%		300,000			300,000
Unsecured notes	2014		5.80	%		300,000			300,000
Secured note	2014		6.00	%		1,430			1,592
Senior notes	2035		5.50	%		250,000			250,000
Senior notes (c)	2016		6.25	%		250,000			250,000
Senior notes (c)	2036		6.875	%		150,000			150,000
Unamortized discount and premium						(8,883	)		(9,857	)
Capitalized lease obligations	2007-2012		(d	)		4,457			5,880

Subtotal (e)						2,877,859			2,878,470

SUNCOR
Notes payable	2008-2013		(f	)		237,671			180,316
Capitalized lease obligations	2007-2010		(g	)		368			328

Subtotal						238,039			180,644

PINNACLE WEST
Senior notes (h)	2011		5.91	%		175,000			175,000
Capitalized lease obligations	2007		5.45	%		—			115

Subtotal						175,000			175,115

Total long-term debt						3,290,898			3,234,229
Less current maturities						163,773			1,596

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES					$	3,127,125		$	3,232,633


(a)		This schedule does not reflect the timing of redemptions that may occur prior to maturity.

(b)		The weighted-average rate was 3.76% at December 31, 2007 and 3.77% at December 31, 2006. Changes in short-term interest rates would affect the costs associated with this debt. In addition, these amounts include $343 million of auction rate debt securities backed by insurance at December 31, 2007 and 2006.

(c)		On August 3, 2006, APS issued $250 million 6.25% notes due 2016 and $150 million 6.875% notes due 2036. A portion of the proceeds was used to repay outstanding commercial paper balances and $84 million of its 6.75% senior note that matured November 15, 2006. The remainder has been used to fund its construction program and other general corporate purposes.

(d)		The weighted-average interest rate was 5.51% at December 31, 2007 and 6.20% at December 31, 2006.

(e)		APS’ long-term debt less current maturities was $2.877 billion at December 31, 2007 and $2.878 billion at December 31, 2006. APS’ current maturities of long-term debt were $1 million at December 31, 2007 and 2006.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(f)		SunCor had $94 million outstanding at December 31, 2007 under its revolving lines of credit. The weighted-average interest rate was 7.27% at December 31, 2007. The remaining amount of approximately $143 million at December 31, 2007 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 1.7%, 2.0% and 2.25%. SunCor had $118 million outstanding at December 31, 2006 under its revolving line of credit. The weighted-average interest rate was 7.08% at December 31, 2006. The remaining amount of approximately $62 million at December 31, 2006 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 2.25%. There is also a note at a fixed rate of 4.25% at December 31, 2007 and 2006

(g)		The weighted-average interest rate was 7.0% at December 31, 2007 and 6.25% at December 31, 2006.

(h)		On February 28, 2006, Pinnacle West entered into a $200 million Senior Notes Uncommitted Master Shelf Agreement with Prudential Investment Management Inc. (“Prudential”). Under the terms of the agreement, Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential at any time prior to December 31, 2007. The maturity of the notes cannot exceed five years. On February 28, 2006, Pinnacle West issued $175 million of its 5.91% senior notes, series A, to Prudential.

Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At December 31, 2007, the ratio was approximately 50% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.7 times under APS’ bank financing agreements as of December 31, 2007. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank financing agreements contain a pricing grid in which interest costs we pay are determined by our current credit ratings.

An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2007, APS’ common equity ratio, as defined, was 54%, its total common equity was approximately $3.4

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

billion, and total capitalization was approximately $6.2 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.5 billion, assuming APS’ total capitalization remains the same.

SunCor has a $150 million loan facility secured primarily by an interest in land, commercial properties, land contracts and homes under construction. The loan facility requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. As of December 31, 2007, the amount of SunCor’s net assets that could not be transferred to Pinnacle West in the form of cash dividends as a result of these covenants was approximately $217 million.

As a result of the restrictions in the preceding two paragraphs, as of December 31, 2007, the restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at December 31, 2007, our consolidated net assets were approximately $3.5 billion). These restrictions do not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions):


Year	Pinnacle West		APS
2008	$	164	$	1
2009		72		1
2010		224		224
2011		578		401
2012		376		376
Thereafter		1,886		1,884

Total	$	3,300	$	2,887

7. Common Stock and Treasury Stock

Our common stock and treasury stock activity during each of the three years 2007, 2006 and 2005 is as follows (dollars in thousands):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Common Stock					Treasury Stock
	Shares		Amount			Shares			Amount
Balance at December 31, 2004		91,802,861	$	1,769,047			(9,522	)	$	(428	)
Common stock issuance (a)		7,274,272		298,330			—			—
Purchase of treasury stock (b)		—		—			(28,124	)		(1,601	)
Reissuance of treasury stock for stock compensation (net)		—		—			17,588			784

Balance at December 31, 2005		99,077,133		2,067,377			(20,058	)		(1,245	)

Common stock issuance		883,933		39,420			—			—
Purchase of treasury stock (b)		—		—			(5,505	)		(229	)
Reissuance of treasury stock for stock compensation (net)		—		—			23,144			1,025
Other		—		7,753			—			—

Balance at December 31, 2006		99,961,066		2,114,550			(2,419	)		(449	)

Common stock issuance		564,404		24,089			—			—
Purchase of treasury stock (b)		—		—			(47,218	)		(1,964	)
Reissuance of treasury stock for stock compensation (net)		—		—			10,132			359
Other		—		(2,852	)		—			—

Balance at December 31, 2007		100,525,470	$	2,135,787			(39,505	)	$	(2,054	)


(a)		On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the net proceeds for general corporate purposes, including making capital contributions to APS, which, in turn, used such funds to pay a portion of the approximately $190 million purchase price to acquire the Sundance Plant and for other capital expenditures incurred to meet the growing needs of APS’ service territory.

(b)		Represents shares of common stock withheld from certain stock awards for tax purposes.

8. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.

We also sponsor other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.

Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. The fair market value of investments in our retirement and postretirement plans is determined using actively-quoted prices when available. When actively-quoted prices are not available, we use prices provided by external sources, models or other valuation methods. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through the application of these methods.

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans are attributable to APS and therefore are recoverable in rates. Accordingly these changes are recorded as a regulatory asset.

The following table provides details of the plans’ benefit costs. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants (dollars in thousands):


	Pension									Other Benefits
	2007			2006			2005			2007			2006			2005
Service cost-benefits earned during the period	$	51,803		$	47,287		$	45,027		$	18,491		$	19,968		$	20,913
Interest cost on benefit obligation		100,736			92,196			87,189			35,284			34,653			34,223
Expected return on plan assets		(107,165	)		(95,912	)		(88,403	)		(42,177	)		(36,930	)		(30,471	)
Amortization of:
Transition (asset) obligation		—			(645	)		(3,227	)		3,005			3,005			3,005
Prior service cost (credit)		2,957			2,401			2,401			(125	)		(125	)		(125	)
Net actuarial loss		16,331			23,366			19,810			3,929			8,662			9,243

Net periodic benefit cost	$	64,662		$	68,693		$	62,797		$	18,407		$	29,233		$	36,788

Portion of cost charged to expense	$	28,063		$	30,912		$	26,375		$	7,989		$	13,155		$	15,451

APS share of costs charged to expense	$	26,548		$	29,203		$	24,169		$	7,557		$	12,428		$	14,159

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2007 and 2006 (dollars in thousands):


	Pension						Other Benefits
	2007			2006			2007			2006
Change in Benefit Obligation
Benefit obligation at January 1	$	1,670,274		$	1,596,068		$	616,985		$	585,678
Service cost		51,803			47,287			18,491			19,968
Interest cost		100,736			92,196			35,284			34,653
Benefit payments		(52,168	)		(49,189	)		(17,763	)		(16,439	)
Actuarial gains		(52,227	)		(19,588	)		(47,872	)		(6,875	)
Plan amendments		2,426			3,500			—			—

Benefit obligation at December 31		1,720,844			1,670,274			605,125			616,985


Change in Plan Assets
Fair value of plan assets at January 1	$	1,214,229		$	1,064,848		$	480,638		$	416,174
Actual return on plan assets		101,138			148,895			26,952			47,988
Employer contributions		52,000			46,500			18,407			29,233
Benefit payments		(48,428	)		(46,014	)		(26,233	)		(12,757	)

Fair value of plan assets at December 31		1,318,939			1,214,229			499,764			480,638

Funded Status at December 31	$	(401,905	)	$	(456,045	)	$	(105,361	)	$	(136,347	)

The following table shows the projected benefit obligation and the accumulated benefit obligation for the pension plan in excess of plan assets as of December 31, 2007 and 2006 (dollars in thousands):


	2007		2006
Projected benefit obligation	$	1,720,844	$	1,670,274
Accumulated benefit obligation		1,484,444		1,426,492
Fair value of plan assets		1,318,939		1,214,229

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2007 and 2006 (dollars in thousands):


	Pension						Other Benefits
	2007			2006			2007			2006
Current asset	$	—		$	—		$	1,321		$	—
Current liability		(3,984	)		(3,540	)		—			—
Noncurrent liability		(397,921	)		(452,505	)		(106,682	)		(136,347	)

Net amount recognized	$	(401,905	)	$	(456,045	)	$	(105,361	)	$	(136,347	)

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the details related to accumulated other comprehensive loss before income taxes as of December 31, 2007 and 2006 (dollars in thousands):


	Pension						Other Benefits
	2007			2006			2007			2006
Net actuarial loss	$	268,532		$	331,054		$	106,407		$	143,079
Prior service cost (credit)		12,401			12,932			(1,045	)		(1,171	)
Transition obligation		—			—			15,024			18,029
APS’ portion recorded as a regulatory asset		(221,787	)		(318,461	)		(116,425	)		(154,531	)

Accumulated other comprehensive loss	$	59,146		$	25,525		$	3,961		$	5,406

The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2008 (dollars in thousands):


	Pension		Other Benefits
Net actuarial loss	$	9,048	$	4,042
Prior service cost (credit)		2,455		(125	)
Transition obligation		—		3,005

Total amounts estimated to be amortized from accumulated other comprehensive income and regulatory assets in 2008	$	11,503	$	6,922

The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:


							Benefit Costs
	Benefit Obligations						For the Years Ended
	As of December 31,						December 31,
	2007			2006			2007			2006
Discount rate-pension		6.25	%		5.90	%		5.90	%		5.66	%
Discount rate-other benefits		6.31	%		5.93	%		5.93	%		5.68	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%
Expected long-term return on plan assets		N/A			N/A			9.00	%		9.00	%
Initial health care cost trend rate		8.00	%		8.00	%		8.00	%		8.00	%
Ultimate health care cost trend rate		5.00	%		5.00	%		5.00	%		5.00	%
Year ultimate health care trend rate is reached		2012			2011			2011			2010

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2008, we are assuming a 9% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):


	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	7	$	(5	)
Effect on service and interest cost components of net periodic other postretirement benefit costs		10		(8	)
Effect on the accumulated other postretirement benefit obligation		94		(76	)

Plan Assets

Pinnacle West’s qualified pension plan and other postretirement benefit plans’ asset allocation at December 31, 2007 and 2006 is as follows:


	Pension									Other Benefits
	2007			2006			Target			2007			2006			Target
Asset Category:
Equity securities		68	%		69	%		68	%		70	%		74	%		70	%
Fixed income		25			25			25			28			25			27
Other		7			6			7			2			1			3

Total		100	%		100	%		100	%		100	%		100	%		100	%

The Board of Directors has delegated oversight of the plan assets to an Investment Management Committee. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with acceptable levels of risk. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West securities, and external management of plan assets.

The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the other postretirement benefit plans. The investment policy for other postretirement benefit plans’ assets is similar to that of the pension plan assets described above.

Contributions

The contribution to our pension plan in 2008 is estimated to be approximately $50 million. The contribution to our other postretirement benefit plans in 2008 is estimated to be approximately

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$20 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

Estimated Future Benefit Payments

Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):


Year	Pension		Other Benefits (a)
2008	$	60,536	$	19,315
2009		66,799		21,246
2010		73,624		23,846
2011		82,764		26,579
2012		93,371		29,293

Years 2013-2017		639,326		194,680


(a)		The expected future other benefit payments take into account the Medicare Part D subsidy.

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2007, costs related to APS’ employees represented 97% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. At December 31, 2007, approximately 15% of total plan assets were in Pinnacle West stock. Pinnacle West recorded expenses for this plan of approximately $7 million for 2007, $6 million for 2006 and $6 million for 2005. APS recorded expenses for this plan of approximately $6 million in 2007, $6 million in 2006 and $6 million in 2005.

9. Leases

In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases and to purchase the property for fair market value at the end of the lease terms. Rent expense is calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the VIE’s involved in the Palo Verde sale leaseback transactions.

In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.

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Total lease expense recognized in the Consolidated Statements of Income was $73 million in 2007, $72 million in 2006 and $71 million in 2005. APS’ lease expense was $66 million in 2007, $64 million in 2006 and $58 million in 2005.

The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2008 to 2015.

Estimated future minimum lease payments for Pinnacle West’s and APS’ operating leases, excluding purchase power agreements, are approximately as follows (dollars in millions):


	Pinnacle West
Year	Consolidated		APS
2008	$	79	$	72
2009		75		69
2010		73		67
2011		68		63
2012		65		61
Thereafter		195		177

Total future lease commitments	$	555	$	509

10. Jointly-Owned Facilities

APS shares ownership of some of its generating and transmission facilities with other companies. Our share of operations and maintenance expense and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2007 (dollars in thousands):

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								Construction
	Percent			Plant in		Accumulated		Work in
	Owned			Service		Depreciation		Progress
Generating facilities:
Palo Verde Units 1 and 3		29.1	%	$	1,939,389	$	1,038,432	$	132,618
Palo Verde Unit 2 (see Note 9)		17.0	%		672,564		303,638		16,630
Four Corners Units 4 and 5		15.0	%		182,052		99,127		12,345
Navajo Generating Station Units 1, 2 and 3		14.0	%		255,592		142,144		1,855
Cholla common facilities (a)		63.9	%(b)		91,636		49,741		31,692
Transmission facilities:
ANPP 500KV System		35.8	%(b)		79,515		24,001		4,399
Navajo Southern System		31.4	%(b)		38,935		12,665		5,575
Palo Verde — Yuma 500KV System		23.9	%(b)		9,230		3,857		3,427
Four Corners Switchyards		27.5	%(b)		3,198		1,304		—
Phoenix — Mead System		17.1	%(b)		36,032		4,823		—
Palo Verde — Estrella 500KV System		55.5	%(b)		74,318		3,990		—
Harquahala		80.0	%(b)		—		—		6,418


(a)		PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.

(b)		Weighted average of interests.

11. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim.

APS currently estimates it will incur $147 million (in 2007 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2007, APS had a regulatory liability of $11 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

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Nuclear Insurance

The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $15 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $13 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $21.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

Fuel and Purchased Power Commitments

Pinnacle West and APS are parties to various fuel and purchased power contracts with terms expiring between 2008 and 2025 that include required purchase provisions. Pinnacle West estimates the contract requirements to be approximately $418 million in 2008; $358 million in 2009; $293 million in 2010; $218 million in 2011; $216 million in 2012; and $1.6 billion thereafter. APS estimates the contract requirements to be approximately $375 million in 2008; $358 million in 2009; $293 million in 2010; $212 million in 2011; $210 million in 2012; and $1.6 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

Of the various fuel and purchased power contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024.

The following table summarizes our actual and estimated take-or-pay commitments (dollars in millions):

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	Actual						Estimated (a)
	2005		2006		2007		2008		2009		2010		2011		2012		Thereafter
Coal take-or-pay commitments	$	48	$	67	$	70	$	81	$	97	$	75	$	77	$	78	$	476


(a)		Total take-or-pay commitments are approximately $884 million. The total net present value of these commitments is approximately $588 million.

Coal Mine Reclamation Obligations

APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation was approximately $91 million at December 31, 2007 and $75 million at December 31, 2006 and is included in Deferred Credits and Other on the Consolidated Balance Sheets.

California Energy Market Issues and Refunds in the Pacific Northwest

FERC

In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006, the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Various parties filed petitions for rehearing on this order. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Several parties sought rehearing of this decision at the Ninth Circuit. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. We currently believe the refund claims at the FERC will have no material adverse impact on our financial position, results of operations or cash flows.

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On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC, and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31, 2006. On December 28, 2006, certain parties petitioned the Supreme Court for a writ of certiorari. This petition was denied on June 18, 2007. The Ninth Circuit issued the mandate for this proceeding on December 4, 2007. The outcome of the further proceedings cannot be predicted at this time.

On July 25, 2001, the FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Petitions for rehearing of this opinion were filed on December 17, 2007. Although the FERC ruling in this matter is being appealed and the FERC has not yet calculated the specific refund amounts at issue, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.

Navajo Nation Litigation

In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.

In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. APS cannot currently predict the outcome of this matter.

Superfund

Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 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.

Salt River Project

Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserts that certain of these failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims that APS owes it approximately $29 million. APS disputes that it is required to pay these amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect that resolution of this matter will have a material adverse impact on our financial position, results of operations, or cash flows.

Litigation

We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.

12. Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term.

Some of APS’ transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.

Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites. The generation sites are strategically located to serve APS Native Load customers. Management expects to continuously use the sites and, thus, cannot estimate a potential closure date. The asset retirement obligations associated with our non-regulated assets are immaterial.

The following schedule shows the change in our asset retirement obligations for 2007 and 2006 (dollars in millions):


	2007			2006
Asset retirement obligations at the beginning of year	$	268		$	269
Changes attributable to:
Liabilities settled		(2	)		(2	)
Accretion expense		20			19
Estimated cash flow revisions		(4	)		(18	)

Asset retirement obligations at the end of year	$	282		$	268

In accordance with SFAS No. 71, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 1.

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income securities and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have recorded the offsetting amount of gains on investment securities in other regulatory liabilities or assets.The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at December 31, 2007 and December 31, 2006 (dollars in millions):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


			Total
			Unrealized
	Fair Value		Gains
2007
Equity securities	$	175	$	68
Fixed income securities		204		5

Total	$	379	$	73


2006
Equity securities	$	164	$	63
Fixed income securities		180		3

Total	$	344	$	66

The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):


	Year Ended December 31,
	2007			2006		2005
Realized gains	$	3		$	9	$	6
Realized losses		(4	)		—		(6	)
Proceeds from the sale of securities		259			255		186

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2007 is as follows (dollars in millions):


	Fair Value
Less than one year	$	10
1 year - 5 years		42
5 years - 10 years		38
Greater than 10 years		114

Total	$	204

13. Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2007 and 2006 is as follows (dollars in thousands, except per share amounts):

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	2007 Quarter Ended								2007
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	695,017	$	862,902	$	1,205,234	$	757,985	$	3,521,138
Operations and maintenance		171,578		177,310		178,419		207,398		734,705
Operating income		68,221		158,769		338,722		53,319		619,031
Income taxes		9,041		40,713		92,055		10,638		152,447
Income from continuing operations		16,464		79,237		201,718		3,713		301,132
Net income		16,530		78,994		208,708		2,911		307,143


	2006 Quarter Ended								2006
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	670,206	$	925,028	$	1,076,442	$	730,072	$	3,401,748
Operations and maintenance		178,427		168,332		164,396		180,122		691,277
Operating income		57,163		191,197		310,440		60,070		618,870
Income taxes		6,793		49,271		98,836		1,518		156,418
Income from continuing operations		11,595		110,843		184,179		10,526		317,143
Net income		12,455		112,154		184,167		18,479		327,255

Earnings per share:


	2007 Quarter Ended
	March 31,		June 30,		September 30,		December 31,
Basic earnings per share:
Income from continuing operations	$	0.16	$	0.79	$	2.01	$	0.04
Net income		0.17		0.79		2.08		0.03

Diluted earnings per share:
Income from continuing operations	$	0.16	$	0.79	$	2.00	$	0.04
Net income		0.16		0.78		2.07		0.03


	2006 Quarter Ended
	March 31,		June 30,		September 30,		December 31,
Basic earnings per share:
Income from continuing operations	$	0.12	$	1.12	$	1.85	$	0.11
Net income		0.13		1.13		1.85		0.19

Diluted earnings per share:
Income from continuing operations	$	0.12	$	1.11	$	1.84	$	0.10
Net income		0.13		1.13		1.84		0.18

14. Fair Value of Financial Instruments

We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2007 and 2006 due to their short maturities.

We hold short-term investments in fixed income securities for purposes other than trading. We believe that the carrying amounts of these investments represent reasonable estimates of their fair values at December 31, 2007 and 2006 due to the short-term reset of interest rates.

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APS also holds investments in fixed income and domestic equity securities for purposes other than trading in its nuclear decommissioning trust. The December 31, 2007 and 2006 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.

On December 31, 2007, the carrying value of our long-term debt for Pinnacle West, excluding capitalized lease obligations was $3.29 billion, with an estimated fair value of $3.20 billion. The carrying value of our long-term debt for Pinnacle West excluding capitalized lease obligations was $3.23 billion on December 31, 2006, with an estimated fair value of $3.19 billion. On December 31, 2007, the carrying value of APS’ long-term debt, excluding capitalized lease obligations, was $2.87 billion, with an estimated fair value of $2.79 billion. The carrying value of APS’ long-term debt excluding capital lease obligations was $2.87 billion on December 31, 2006, with an estimated fair value of $2.84 billion. The fair value estimates are based on quoted market prices of the same or similar issues.

15. Earnings Per Share

The following table presents earnings per weighted-average common share outstanding for the years ended December 31, 2007, 2006 and 2005:


	2007		2006		2005
Basic earnings per share:
Income from continuing operations	$	3.00	$	3.19	$	2.31
Income (loss) from discontinued operations		0.06		0.10		(0.48	)

Earnings per share — basic	$	3.06	$	3.29	$	1.83

Diluted earnings per share:
Income from continuing operations	$	2.99	$	3.17	$	2.31
Income (loss) from discontinued operations		0.06		0.10		(0.49	)

Earnings per share — diluted	$	3.05	$	3.27	$	1.82

Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 579,000 shares in 2007, 593,000 shares in 2006 and 106,000 shares in 2005. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 100,834,871 shares in 2007, 100,010,108 shares in 2006 and 96,589,949 shares in 2005.

Options to purchase 114,213 shares of common stock were outstanding at December 31, 2007 but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 437,401 at December 31, 2006 and 495,367 at December 31, 2005.

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16. Stock-Based Compensation

Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and some of our subsidiaries.

The 2007 Long-Term Incentive Plan (“2007 Plan”) allows Pinnacle West to grant incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, performance cash awards, dividend equivalents and stock to eligible individuals. We have reserved 8 million shares of common stock for issuance under the 2007 plan plus additional shares that become available for issuance under prior stock plans (“Prior Plans”). Under the 2007 Plan, any shares of stock that are potentially deliverable under any award granted under a Prior Plan will be added to the number of shares of stock available for grant under the 2007 Plan if the award expires or is cancelled or terminated without a delivery of such shares to the participant. In addition, any shares of stock that have been issued in connection with any award granted under a Prior Plan will be added to the number of shares available for grant under the 2007 Plan if the award is cancelled, forfeited, or terminated such that those shares are returned to the Company. No more than 500,000 shares of stock may be granted to any one participant during a calendar year. The maximum performance-based award (other than a performance cash award) payable to any one participant during a performance period is 500,000 shares of stock or the cash equivalent. The plan also provides for the granting of new incentive and non-qualified stock options at a price per share equal to at least 100% of the fair market value of the common stock at the time of grant. The terms of the options cannot be longer than 10 years and the options cannot be repriced during their terms.

The 2002 Long-Term Incentive Plan (“2002 Plan”) relates to outstanding performance shares but no new awards may be granted under the plan. Performance share awards under the 2002 Plan contain performance criteria that affect the number of shares that ultimately vest. Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year performance period. The number of shares each recipient ultimately receives, if any, is based upon the percentile ranking of Pinnacle West’s earnings per share growth rate at the end of the three-year period as compared with the earnings per share growth rate of all relevant companies in a specified utilities index. The fair value of the grant is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Management evaluates the probability of meeting the performance criteria at each balance sheet date and related compensation cost is amortized over the performance period on a straight-line basis. If the goals are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.

The 1994 Long-Term Incentive Plan (“1994 Plan”) relates to outstanding options but no new awards may be granted under the plan. Options vest by thirds over a three-year period beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also includes outstanding shares of restricted stock.

In 2006, Retention Unit Awards (“Retention Units”) were granted to key employees. Each Retention Unit represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Retention Units will be redeemed the first business day of calendar years 2007, 2008, 2009 and 2010. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. The Retention Units vest over a four-year period from 2006 through 2009, unless the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

employee is eligible to retire, in which case the employee’s Retention Units are immediately vested and the compensation expense is immediately recognized. As this award is accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, are remeasured at each balance sheet date, using Pinnacle West’s closing stock price. The amount of cash to settle the payment on the first business day of 2007 was $1.6 million.

In 2007 under the 2007 Plan, Restricted Stock Unit Awards (“Restricted Stock Units”) were granted to officers and key employees. Each officer and key employee had to elect to receive payment for the vested Restricted Stock Units in cash or in fully transferable shares of stock. The fair value of the stock election is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Each Restricted Stock Unit cash election represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Restricted Stock Units will be redeemed February 20th of calendar years 2008, 2009, 2010 and 2011. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the Restricted Stock Unit from the date of grant to the date of payment plus interest. Restricted Stock Units vest over a four-year period from 2007 through 2010, unless the employee is eligible to retire, in which case the employee’s Restricted Stock Units are immediately vested (with the same redemption dates) and the compensation expense is immediately recognized; however, the Restricted Stock Units will be redeemed on the pre-established valuation dates. As the Restricted Stock Unit cash election award is accounted for as a liability award, the fair market value of the outstanding Restricted Stock Unit cash election is measured at each balance sheet date, using Pinnacle West’s closing stock price.

The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $6 million in 2007, $13 million in 2006 and $6 million in 2005. The compensation cost that Pinnacle West has capitalized was immaterial in 2007, 2006 and 2005. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $2 million in 2007, $5 million in 2006 and $2 million in 2005. APS’ share of compensation cost that has been charged against income was $6 million in 2007, $12 million in 2006 and $5 million in 2005.

The following table is a summary of option activity under our equity incentive plans as of December 31, 2007 and changes during the year:

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


					Weighted-
					Average		Aggregate
			Weighted-		Remaining		Intrinsic Value
	Shares		Average Exercise		Contractual Term		(dollars in
Options	(in thousands)		Price		(Years)		thousands)
Outstanding at January 1, 2007		1,088	$	40.64
Exercised		207		39.48
Forfeited or expired		20		43.64

Outstanding at December 31, 2007		861		40.84		3.0	$	2,187

Exercisable at December 31, 2007		861		40.84		3.0	$	2,187

There were no options granted during the years 2005 through 2007. The intrinsic value of options exercised was $2 million for 2007, $5 million for 2006 and $4 million for 2005.

The following table is a summary of the status of stock compensation awards, other than options, as of December 31, 2007 and changes during the year:


	Shares		Weighted-Average Grant-Date
Nonvested shares	(in thousands)		Fair Value
Nonvested at January 1, 2007		429	$	41.45
Granted		164		48.02
Vested		147		41.38
Forfeited		67		42.40

Nonvested at December 31, 2007		379		43.64

As of December 31, 2007, there was $7 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 1.3 years. The total fair value of shares vested during 2007 was $6 million, $10 million for 2006 and $3 million for 2005.

The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2007, 2006 and 2005:

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PINNACLE WEST CAPITAL CORPORATION
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	2007		2007 Grant			2006		2006 Grant				2005 Grant
	Shares/		Date Fair			Shares/		Date Fair		2005		Date Fair
	Units		Value (a)			Units		Value (a)		Shares		Value (a)
Restricted stock award units		27,026		$	46.58		—	$	—		—	$	—
Restricted cash award units		107,891			46.58		—		—		—		—
Performance share awards		134,917			48.42		274,070		41.50		215,300		41.36
Stock ownership incentive awards		—			—		12,526		41.50		13,114		44.13
Retention unit awards		—			—		123,197		49.92		—		—
Special grant		2,000			41.88		—		—		—		—


(a)		Restricted stock units, performance shares, special grant and stock ownership incentive awards priced at the closing market price on the grant date.

Cash received from options exercised under our share-based payment arrangements was $8 million for 2007, $22 million for 2006 and $17 million for 2005. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was $1 million for 2007, $2 million for 2006 and $1 million for 2005.

Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares during 2008.

17. Business Segments

Pinnacle West’s two reportable business segments are:

	•		our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and

	•		our real estate segment, which consists of SunCor’s real estate development and investment activities.

Financial data for 2007, 2006 and 2005 is provided as follows (dollars in millions):

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PINNACLE WEST CAPITAL CORPORATION
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	Business Segments for the Year Ended December 31, 2007
	Regulated
	Electricity			Real Estate
	Segment			Segment			All other (a)			Total
Operating revenues	$	2,918		$	212		$	391		$	3,521
Purchased power and fuel costs		1,141			—			294			1,435
Other operating expenses		836			193			66			1,095

Operating margin		941			19			31			991
Depreciation and amortization		366			4			2			372
Interest expense		180			4			2			186
Other expense (income)		(18	)		(10	)		8			(20	)

Income from continuing operations before income taxes		413			21			19			453
Income taxes		139			7			6			152

Income from continuing operations		274			14			13			301
Income from discontinued operations — net of income tax expense of $6 million (see Note 22)		—			9			(3	)		6

Net income	$	274		$	23		$	10		$	307

Total assets	$	10,356		$	661		$	145		$	11,162

Capital expenditures	$	900		$	161		$	3		$	1,064


	Business Segments for the Year Ended December 31, 2006
	Regulated
	Electricity			Real Estate
	Segment			Segment			All other (a)		Total
Operating revenues	$	2,635		$	400		$	367	$	3,402
Purchased power and fuel costs		960			—			291		1,251
Other operating expenses		791			325			57		1,173

Operating margin		884			75			19		978
Depreciation and amortization		354			3			2		359
Interest expense		173			1			2		176
Other expense (income)		(22	)		(11	)		2		(31	)

Income from continuing operations before income taxes		379			82			13		474
Income taxes		120			32			5		157

Income from continuing operations		259			50			8		317
Income from discontinued operations — net of income tax expense of $7 million (see Note 22)		—			10			—		10

Net income	$	259		$	60		$	8	$	327

Total assets	$	10,001		$	591		$	226	$	10,818

Capital expenditures	$	662		$	201		$	7	$	870

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Business Segments for the Year Ended December 31, 2005
	Regulated
	Electricity			Real Estate
	Segment			Segment			All other (a)			Total
Operating revenues (b)	$	2,237		$	338		$	413		$	2,988
Purchased power and fuel costs		595			—			293			888
Other operating expenses		740			278			80			1,098
Regulatory disallowance (see Note 3)		139			—			—			139

Operating margin		763			60			40			863
Depreciation and amortization		343			3			2			348
Interest expense		169			2			2			173
Other expense (income)		(6	)		(3	)		1			(8	)

Income from continuing operations before income taxes		257			58			35			350
Income taxes		90			23			14			127

Income from continuing operations		167			35			21			223
Income (loss) from discontinued operations — net of income tax benefit of $(30) (see Note 22) (c)		—			17			(64	)		(47	)

Net income (loss)	$	167		$	52		$	(43	)	$	176

Capital expenditures	$	811		$	106		$	11		$	928


(a)		All other activities relate to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.

(b)		Effective April 1, 2005, revenues of approximately $40 million from Off-System Sales, which were previously reported in the other segment, began being reported in the regulated electricity segment in accordance with the retail rate case settlement.

(c)		The other segment primarily relates to the sale and operations of Silverhawk. See Note 22.

18. Derivative and Energy Trading Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of December 31, 2007, we hedged certain exposures to the price variability of commodities for a maximum of 39 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

We recognize all derivatives, except those which qualify for a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales exception and are accounted for under the accrual method of accounting. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value of an asset or liability.

For its regulated operations, APS defers for future rate recovery 90% of gains and losses on derivatives that would otherwise be recognized in income. In the following discussion, amounts that would otherwise be recognized in income will be recorded as either a regulatory asset or liability and have no effect on earnings to the extent these amounts are eligible to be recovered through the PSA.

We assess hedge effectiveness both at inception and on a continuing basis. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated and is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.

Both non-trading and trading derivatives that do not qualify for a scope exception are classified as assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge accounting treatment. Non-trading derivatives, or any portion thereof that are not effective hedges, are adjusted to fair value through income. Realized gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.

All gains and losses (realized and unrealized) on trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis. Trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Consolidated Statement of Income, but this does not impact our financial condition, net income or cash flows.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Flow Hedges

The changes in the fair value of our hedged positions included in the Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2007, 2006 and 2005 are comprised of the following (dollars in thousands):


	2007		2006			2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	1,430	$	(5,666	)	$	14,289
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		—		(10	)		620
Gains from the discontinuance of cash flow hedges		320		453			556

During 2008, we estimate that a net gain of $18 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).

The following table summarizes our assets and liabilities from risk management and trading activities in accordance with FIN 39-1 at December 31, 2007 and 2006 (dollars in thousands):


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2007	Assets		Assets		Liabilities			Other			(Liability)
Mark-to-market	$	26,333	$	48,928	$	(30,786	)	$	(4,701	)	$	39,774
Margin account		30,650		—		6,148			—			36,798
Collateral provided to counterparties		622		—		128			—			750
Collateral provided from counterparties		—		—		—			—			—

Total	$	57,605	$	48,928	$	(24,510	)	$	(4,701	)	$	77,322

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


				Investments					Deferred
	Current			and Other		Current			Credits and			Net Asset
December 31, 2006	Assets			Assets		Liabilities			Other			(Liability)
Mark-to-market	$	119,486		$	66,810	$	(99,364	)	$	(71,608	)	$	15,324
Collateral provided to counterparties		4,027			—		2,701			3,259			9,987
Collateral provided from counterparties		(54,000	)		—		(90	)		—			(54,090	)
Margin account, options and emission allowances — at cost		43,034			839		19,689			—			63,562

Total	$	112,547		$	67,649	$	(77,064	)	$	(68,349	)	$	34,783

We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $31 million at December 31, 2007 and an asset of $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

See Note 23 for discussion of the adoption of FIN 39-1.

Credit Risk

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 12% of Pinnacle West’s $106 million of risk management and trading assets as of December 31, 2007. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ securities is rated as investment grade by the credit rating agencies, including the counterparty discussed above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated net income for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 “Derivative Accounting” for a discussion of our credit valuation adjustment policy.

19. Other Income and Other Expense

The following table provides detail of other income and other expense for 2007, 2006 and 2005 (dollars in thousands):

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2007			2006			2005
Other income:
Interest income	$	11,656		$	18,867		$	14,793
SunCor other income (a)		10,702			10,881			2,623
SO2 emission allowance sales and other (b)		—			10,782			3,187
Investment gains — net		—			2,537			752
Miscellaneous		2,336			949			2,005

Total other income	$	24,694		$	44,016		$	23,360


Other expense:
Non-operating costs (b)	$	(14,021	)	$	(16,223	)	$	(13,589	)
Asset dispositions		—			(2,056	)		(9,759	)
Investment losses — net		(2,339	)		—			—
Miscellaneous		(9,523	)		(9,521	)		(3,368	)

Total other expense	$	(25,883	)	$	(27,800	)	$	(26,716	)


(a)		Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.

(b)		As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

20. Variable-Interest Entities

SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $38 million at December 31, 2007 and $39 million at December 31, 2006.

21. Guarantees

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2007 are as follows (dollars in millions):


	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
Parental:
Pinnacle West Marketing & Trading	$	25		1	$	—		—
APSES		18		1		20		1
APS		4		1		—		—

Total	$	47			$	20

At December 31, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in 2009. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2007, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $83 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, at December 31, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2008. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

22. Discontinued Operations

SunCor(real estate segment)-In 2007, 2006 and 2005, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144. As a result of the sales, we recorded a gain

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

from discontinued operations of approximately $10 million ($17 million pretax) in 2007; $9 million ($15 million pretax) in 2006; and $15 million ($25 million pretax) in 2005.

Silverhawk(other)-In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on January 10, 2006. As a result of this sale, we recorded a loss from discontinued operations of approximately $56 million ($91 million pretax) in the second quarter of 2005. The chart below includes the revenues and expenses related to the operations of Silverhawk.

Other —Includes activities related to APSES in 2007 and to El Dorado in 2006 and 2005.

The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2007, 2006 and 2005 (dollars in millions):


	2007			2006			2005
Revenue:
SunCor — commercial operations	$	6		$	3		$	9
Silverhawk		—			1			95

Total revenue	$	6		$	4		$	104


Income (loss) before taxes:
SunCor — commercial operations	$	15		$	17		$	28
Silverhawk (a)		—			1			(111	)
Other		(5	)		(1	)		6

Total income (loss) before taxes	$	10		$	17		$	(77	)


Income (loss) after taxes:
SunCor — commercial operations	$	9		$	10		$	17
Silverhawk		—			1			(67	)
Other		(3	)		(1	)		3

Total income (loss) after taxes	$	6		$	10		$	(47	)


(a)		Income before income taxes includes an interest expense allocation, net of capitalized amounts, of $13 million in 2005. The allocation was based on Pinnacle West’s weighted-average interest rate applied to the net property, plant and equipment.

23. Subsequent Events

We adopted FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1) on January 1, 2008. In accordance with this guidance, we elected to offset the fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting arrangement. Collateral was previously reported in other current assets or other current liabilities on our Consolidated Balance Sheet. The guidance requires retrospective application for all prior periods presented. As a result, our Consolidated Balance Sheet and Consolidated Statement of Cash Flows line items decreased by the following amounts (dollars in thousands):

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	As originally		Reclassifications
	reported in the		as a result of the
	2007		adoption of			After adoption of
Balance Sheet - December 31, 2007	Form 10-K		FIN 39-1			FIN 39-1
Current Assets — Assets from risk management and trading activities	$	97,373	$	(39,768	)	$	57,605
Current Assets — Other current assets		34,738		(750	)		33,988
Investments and Other Assets — Assets from long-term risk management and trading activities		89,913		(40,985	)		48,928

Current Liabilities — Liabilities from risk management and trading activities		65,028		(40,518	)		24,510
Deferred Credits and Other - Liabilities from long-term risk management and trading activities		45,686		(40,985	)		4,701


	As originally		Reclassifications
	reported in the		as a result of the
	2007		adoption of			After adoption of
Balance Sheet - December 31, 2006	Form 10-K		FIN 39-1			FIN 39-1
Current Assets — Assets from risk management and trading activities	$	641,040	$	(528,493	)	$	112,547
Current Assets — Other current assets		27,078		(9,988	)		17,090
Investments and Other Assets — Assets from long-term risk management and trading activities		167,211		(99,562	)		67,649

Current Liabilities — Liabilities from risk management and trading activities		558,195		(481,131	)		77,064
Current Liabilities — Other current liabilities		134,123		(54,091	)		80,032
Deferred Credits and Other — Liabilities from long-term risk management and trading activities		171,170		(102,821	)		68,349

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


				Reclassifications
	As originally			as a result of the
Statement of Cash Flows —	reported in the			adoption of			After adoption of
Year ended December 31, 2007	2007 Form 10-K			FIN 39-1			FIN 39-1
Change in other long-term assets	$	17,390		$	(41,216	)	$	(23,826	)
Change in margin and collateral accounts — assets		—			(37,371	)		(37,371	)
Change in risk management and trading — liabilities		(14,450	)		14,450			—
Change in margin and collateral accounts — liabilities		—			19,284			19,284
Collateral		(44,853	)		44,853			—


				Reclassifications
	As originally			as a result of the
Statement of Cash Flows —	reported in the			adoption of			After adoption of
Year ended December 31, 2006	2007 Form 10-K			FIN 39-1			FIN 39-1
Change in other long-term assets	$	20,330		$	(2,789	)	$	17,541
Change in margin and collateral accounts — assets		—			(249,792	)		(249,792	)
Change in risk management and trading — liabilities		(133,197	)		133,197			—
Change in margin and collateral accounts — liabilities		—			(46,444	)		(46,444	)
Collateral		(165,828	)		165,828			—


				Reclassifications
	As originally			as a result of the
Statement of Cash Flows —	reported in the			adoption of			After adoption of
Year ended December 31, 2005	2007 Form 10-K			FIN 39-1			FIN 39-1
Other current assets	$	(6,815	)	$	5,420		$	(1,395	)
Change in other long-term assets		(97,893	)		62,100			(35,793	)
Change in margin and collateral accounts — assets		—			251,925			251,925
Change in risk management and trading — liabilities		110,393			(110,393	)		—
Change in margin and collateral accounts — liabilities		—			(17,012	)		(17,012	)
Collateral		192,040			(192,040	)		—

During the first quarter of 2008, SunCor entered into an agreement to sell certain commercial properties. As a result, we reclassified the related real estate segment revenues, real estate operating

116

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

costs, depreciation expense and interest charges to discontinued operations on the 2007 Consolidated Statements of Income and Consolidated Statement of Cash Flows in accordance with SFAS No. 144. See Note 22.

117

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(ARIZONA PUBLIC SERVICE COMPANY)

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

February 27, 2008

118

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of
Arizona Public Service Company
Phoenix, Arizona

We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2007 and 2006, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.

119

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

As reflected in the statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Planseffective December 31, 2006.

As discussed in Note 23, the Company adopted the provisions of FASB Staff Position No. FIN 39-1.

/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP

Phoenix, Arizona
February 27, 2008
(November 25, 2008 as to the effects of the adoption of FASB Staff Position No. FIN 39-1 as described in Note 23).

120

ARIZONA PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME

(dollars in thousands)


	Year Ended December 31,
	2007			2006			2005
Electric Operating Revenues	$	2,936,277		$	2,658,513		$	2,270,793

Operating Expenses:
Fuel and purchased power		1,151,392			969,767			688,982
Operations and maintenance		710,077			665,631			591,941
Depreciation and amortization		365,430			353,057			325,174
Income taxes (Notes 4 and S-1)		155,735			144,127			157,273
Other taxes		127,648			127,989			125,810

Total		2,510,282			2,260,571			1,889,180


Operating Income		425,995			397,942			381,613


Other Income (Deductions):
Regulatory disallowance (Note 3)		—			—			(138,562	)
Income taxes (Notes 4 and S-1)		4,578			5,200			59,263
Allowance for equity funds used during construction		21,195			14,312			11,191
Other income (Note S-4)		16,727			31,902			22,141
Other expense (Note S-4)		(21,630	)		(23,830	)		(23,204	)

Total		20,870			27,584			(69,171	)


Interest Deductions:
Interest on long-term debt		161,030			149,240			138,476
Interest on short-term borrowings		9,564			9,529			7,026
Debt discount, premium and expense		4,639			4,363			4,085
Allowance for borrowed funds used during construction		(12,308	)		(7,336	)		(7,624	)

Total		162,925			155,796			141,963


Net Income	$	283,940		$	269,730		$	170,479

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

121

ARIZONA PUBLIC SERVICE COMPANY

BALANCE SHEETS

(dollars in thousands)


	December 31,
	2007			2006
ASSETS
Utility Plant (Notes 1, 6, 9 and 10)
Electric plant in service and held for future use	$	11,582,862		$	11,094,868
Less accumulated depreciation and amortization		3,994,777			3,789,534

Net		7,588,085			7,305,334

Construction work in progress		622,693			365,704
Intangible assets, net of accumulated amortization of $250,268 and $217,099		105,225			95,601
Nuclear fuel, net of accumulated amortization of $68,375 and $50,741		69,271			60,100

Total utility plant		8,385,274			7,826,739


Investments and Other Assets
Decommissioning trust accounts (Note 12)		379,347			343,771
Assets from risk management and trading activities (Note S-3)		41,603			5,335
Other assets		69,570			67,763

Total investments and other assets		490,520			416,869


Current Assets:
Cash and cash equivalents		52,151			81,870
Investment in debt securities		—			32,700
Customer and other receivables		402,244			410,436
Allowance for doubtful accounts		(4,265	)		(4,223	)
Materials and supplies (at average cost)		149,759			125,802
Fossil fuel (at average cost)		27,792			21,973
Assets from risk management and trading activities (Note S-3)		34,087			67,798
Deferred income taxes (Notes 4 and S-1)		38,707			19,220
Other		16,545			11,508

Total current assets		717,020			767,084


Deferred Debits:
Deferred fuel and purchased power regulatory asset (Notes 1, 3, 4 and S-1)		110,928			160,268
Other regulatory assets (Notes 1, 3, 4 and S-1)		514,353			686,016
Unamortized debt issue costs		24,373			26,393
Other		78,934			65,397


Total deferred debits		728,588			938,074


Total Assets	$	10,321,402		$	9,948,766

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

122

ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)


	December 31,
	2007			2006
LIABILITIES AND EQUITY
Capitalization:
Common stock	$	178,162		$	178,162
Additional paid-in capital (Note 3)		2,105,466			2,065,918
Retained earnings		1,076,557			960,405
Accumulated other comprehensive income (loss):
Pension and other postretirement benefits (Note 8)		(21,782	)		—
Derivative instruments		13,038			2,988

Common stock equity		3,351,441			3,207,473
Long-term debt less current maturities (Note 6)		2,876,881			2,877,502

Total capitalization		6,228,322			6,084,975


Current Liabilities:
Short-term debt		218,000			—
Current maturities of long-term debt (Note 6)		978			968
Accounts payable		239,923			223,417
Accrued taxes		374,444			381,444
Accrued interest		38,262			45,254
Customer deposits		71,376			61,900
Liabilities from risk management and trading activities (Note S-3)		19,921			19,445
Other		92,802			74,128

Total current liabilities		1,055,706			806,556


Deferred Credits and Other:
Deferred income taxes (Notes 4 and S-1)		1,250,028			1,215,862
Regulatory liabilities (Notes 1, 3, 4, and S-1)		642,564			635,431
Liability for asset retirements (Note 12)		281,903			268,389
Pension and other postretirement liabilities (Note 8)		469,945			551,531
Customer advances for construction		94,801			71,211
Unamortized gain — sale of utility plant (Note 9)		36,606			41,182
Liabilities from risk management and trading activities (Note S-3)		4,573			42,140
Other		256,954			231,489

Total deferred credits and other		3,037,374			3,057,235


Commitments and Contingencies (See Notes)

Total Liabilities and Equity	$	10,321,402		$	9,948,766

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

123

ARIZONA PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS

(dollars in thousands)


	Year Ended December 31,
	2007			2006			2005
Cash Flows from Operating Activities:
Net income	$	283,940		$	269,730		$	170,479
Adjustments to reconcile net income to net cash provided by operating activities:
Regulatory disallowance		—			—			138,562
Depreciation and amortization including nuclear fuel		395,890			381,173			353,082
Deferred fuel and purchased power		(196,136	)		(252,849	)		(172,756	)
Deferred fuel and purchased power amortization		231,106			265,337			—
Deferred fuel and purchased power disallowance		14,370			—			—
Allowance for equity funds used during construction		(21,195	)		(14,312	)		(11,191	)
Deferred income taxes		(44,478	)		(305	)		9,659
Change in derivative mark-to-market valuations		(6,758	)		6,893			3,492
Changes in current assets and liabilities:
Customer and other receivables		23,882			20,970			(56,152	)
Materials, supplies and fossil fuel		(29,776	)		(14,381	)		(12,268	)
Other current assets		(8,056	)		3,666			(2,292	)
Accounts payable		(2,797	)		5,825			(12,372	)
Accrued taxes		13,802			23,678			67,454
Other current liabilities		20,231			45,125			(37,781	)
Change in margin and collateral accounts — liabilities		27,624			(166,088	)		126,705
Change in margin and collateral accounts — assets		11,252			(205,752	)		173,019
Changes in unrecognized tax benefits		27,773			—			—
Change in other long-term assets		(23,577	)		2,828			(24,752	)
Change in other long-term liabilities		48,718			22,175			9,002

Net cash flow provided by operating activities		765,815			393,713			721,890

Cash Flows from Investing Activities:
Capital expenditures		(882,357	)		(648,743	)		(609,857	)
Transfer of PWEC Dedicated Assets to APS		—			—			(500,000	)
Purchase of Sundance Plant		—			—			(185,046	)
Allowance for borrowed funds used during construction		(12,308	)		(7,336	)		(7,624	)
Purchases of investment securities		(36,525	)		(1,291,903	)		(1,476,623	)
Proceeds from sale of investment securities		69,225			1,259,203			1,657,798
Proceeds from nuclear decommissioning trust sales		259,026			254,651			186,215
Investment in nuclear decommissioning trust		(279,768	)		(275,393	)		(204,633	)
Repayment of loan by Pinnacle West Energy		—			—			500,000
Other		1,211			(4,470	)		(5,372	)

Net cash flow used for investing activities		(881,496	)		(713,991	)		(645,142	)

Cash Flows from Financing Activities:
Issuance of long-term debt		—			395,481			411,787
Short-term borrowings — net		218,000			—			—
Equity infusion		39,548			212,820			250,000
Dividends paid on common stock		(170,000	)		(170,000	)		(170,000	)
Repayment and reacquisition of long-term debt		(1,586	)		(86,086	)		(568,177	)

Net cash flow (used for) provided by financing activities		85,962			352,215			(76,390	)

Net (decrease) increase in cash and cash equivalents		(29,719	)		31,937			358
Cash and cash equivalents at beginning of year		81,870			49,933			49,575

Cash and cash equivalents at end of year	$	52,151		$	81,870		$	49,933

Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds	$	186,183		$	117,831		$	34,252
Interest, net of amounts capitalized	$	165,279		$	131,183		$	146,207

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

124

ARIZONA PUBLIC SERVICE COMPANY

STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)


	Year Ended December 31,
	2007			2006			2005
COMMON STOCK	$	178,162		$	178,162			$	178,162


ADDITIONAL PAID-IN CAPITAL		2,105,466			2,065,918				1,853,098


RETAINED EARNINGS
Balance at beginning of year		960,405			860,675				860,196
Net income		283,940			269,730				170,479
Common stock dividends		(170,000	)		(170,000	)			(170,000	)
Cumulative effect of change in accounting for income taxes (Note S-1)		2,212			—				—

Balance at end of year		1,076,557			960,405				860,675


ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		2,988			93,290				(52,760	)
Pension and other postretirement benefits (Note 8):
Unrealized actuarial loss, net of tax benefit of ($15,126)		(23,304	)		—				—
Prior service cost, net of tax benefit of ($463)		(713	)		—				—
Amortization to income:
Actuarial loss, net of tax expense of $1,238		1,908			—				—
Prior service cost, net of tax expense of $212		327			—				—
Minimum pension liability adjustment, net of tax expense (benefit) of $27,424 and ($9,023)		—			42,731				(15,045	)
Adjustment to reflect a change in accounting, net of tax expense of $27,760		—			43,401				—
Derivative instruments:
Net unrealized gain (loss), net of tax expense (benefit) of $1,369, ($111,367) and $140,135		2,040			(173,872	)			218,656
Reclassification of net realized (gains) losses to income, net of tax expense (benefit) of $5,164, ($1,657) and ($37,082)		8,010			(2,562	)			(57,561	)

Balance at end of year		(8,744	)		2,988				93,290


TOTAL COMMON STOCK EQUITY	$	3,351,441		$	3,207,473			$	2,985,225


COMPREHENSIVE INCOME
Net income	$	283,940		$	269,730			$	170,479
Other comprehensive income (loss)		(11,732	)		(133,703	)			146,050

Total comprehensive income	$	272,208		$	136,027			$	316,529

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

125

Certain notes to Arizona Public Service Company’s financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.


		APS’
	Consolidated	Supplemental
	Footnote	Footnote
	Reference	Reference
Summary of Significant Accounting Policies	Note 1	—
New Accounting Standards	Note 2	—
Regulatory Matters	Note 3	—
Income Taxes	Note 4	Note S-1
Lines of Credit and Short-Term Borrowings	Note 5	—
Long-Term Debt	Note 6	—
Common Stock and Treasury Stock	Note 7	—
Retirement Plans and Other Benefits	Note 8	—
Leases	Note 9	—
Jointly-Owned Facilities	Note 10	—
Commitments and Contingencies	Note 11	—
Asset Retirement Obligations	Note 12	—
Selected Quarterly Financial Data (Unaudited)	Note 13	Note S-2
Fair Value of Financial Instruments	Note 14	—
Earnings Per Share	Note 15	—
Stock-Based Compensation	Note 16	—
Business Segments	Note 17	—
Derivative and Energy Trading Accounting	Note 18	Note S-3
Other Income and Other Expense	Note 19	Note S-4
Variable Interest Entities	Note 20	—
Guarantees	Note 21	—
Discontinued Operations	Note 22	—
Related Party Transactions	—	Note S-5
Subsequent Events	Note 23	Note S-6

126

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

S-1. Income Taxes

APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’ taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.

As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next six months, we expect that the IRS will finalize its examination of the 2001 return, which will include a settlement on the tax accounting method change. Although the ultimate outcome of this matter cannot currently be predicted, the current status of the examination has resulted in changes in our judgment which are reflected in the reconciliation of the total amounts of unrecognized tax benefits presented below. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows. We do not expect that there will be any other significant increases or decreases in our unrecognized tax benefits within the next 12 months.

We adopted FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.

127

NOTES TO ARIZONA PUBLIC SERVICE COMPANY


Total unrecognized tax benefits, January 1, 2007	$	126,700
Additions for tax positions of the current year		—
Additions for tax positions of prior years		66,610
Reductions for tax positions of prior years for:
Changes in judgment		(37,419	)
Settlements with taxing authorities		(1,418	)
Lapses of applicable statute of limitations		—

Total unrecognized tax benefits, December 31, 2007	$	154,473

Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately $4 million of tax positions that, if recognized, would decrease our effective tax rate.

As of December 31, 2007, the total amount of interest expense recognized in the statement of financial position related to unrecognized tax benefits was $56 million. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of APS’ income tax expense are as follows (dollars in thousands):


	Year Ended December 31,
	2007			2006		2005
Current:
Federal	$	168,607		$	114,971	$	79,917
State		27,028			21,442		8,434

Total current		195,635			136,413		88,351
Deferred		(44,478	)		2,514		9,659

Total income tax expense	$	151,157		$	138,927	$	98,010

On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.

The following chart compares APS’ pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):

128

NOTES TO ARIZONA PUBLIC SERVICE COMPANY


	Year Ended December 31,
	2007			2006			2005
Federal income tax expense at 35% statutory rate	$	152,284		$	143,030		$	93,971
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		17,540			15,684			8,986
Credits and favorable adjustments related to prior years resolved in current year		(11,432	)		(10,518	)		—
Medicare Subsidy Part-D		(3,100	)		(3,036	)		(2,465	)
Allowance for equity funds used during construction (see Note 1)		(6,900	)		(4,656	)		(3,694	)
Other		2,765			(1,577	)		1,212

Income tax expense	$	151,157		$	138,927		$	98,010

The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):


	December 31,
	2007			2006
Current asset	$	38,707		$	19,220
Long-term liability		(1,250,028	)		(1,215,862	)

Accumulated deferred income taxes — net	$	(1,211,321	)	$	(1,196,642	)

129

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

The components of the net deferred income tax liability were as follows (dollars in thousands):


	December 31,
	2007			2006
DEFERRED TAX ASSETS
Regulatory liabilities:
Asset retirement obligation	$	214,607		$	203,846
Federal excess deferred income tax		11,091			12,714
Tax benefit of Medicare subsidy		11,727			18,214
Other		26,579			27,283
Risk management and trading activities		12,112			37,468
Pension and other postretirement liabilities		197,620			257,910
Deferred gain on Palo Verde Unit 2 sale-leaseback		14,408			16,160
Other		116,491			86,442

Total deferred tax assets		604,635			660,037

DEFERRED TAX LIABILITIES
Plant-related		(1,538,183	)		(1,509,812	)
Risk management and trading activities		(17,483	)		(13,160	)
Regulatory assets:
Deferred fuel and purchased power		(43,661	)		(62,889	)
Deferred fuel and purchased power — mark-to-market		(2,782	)		(24,427	)
Pension and other postretirement benefits		(133,120	)		(185,602	)
Other		(80,727	)		(60,789	)

Total deferred tax liabilities		(1,815,956	)		(1,856,679	)

Accumulated deferred income taxes — net	$	(1,211,321	)	$	(1,196,642	)

130

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

S-2. Selected Quarterly Financial Data (Unaudited)

Quarterly financial information for 2007 and 2006 is as follows (dollars in thousands):


	2007 Quarter Ended,								2007
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	538,260	$	721,759	$	1,047,062	$	629,196	$	2,936,277
Operations and maintenance		165,934		170,631		171,963		201,549		710,077
Operating income		40,589		109,643		238,144		37,619		425,995
Net income		4,317		75,090		204,257		276		283,940


	2006 Quarter Ended,									2006
	March 31,			June 30,		September 30,		December 31,		Total
Operating revenues	$	476,869		$	718,850	$	886,686	$	576,108	$	2,658,513
Operations and maintenance		173,353			164,373		156,170		171,735		665,631
Operating income		25,044			119,967		200,580		52,351		397,942
Net income (loss)		(5,521	)		93,757		168,634		12,860		269,730

S-3. Derivative and Energy Trading Accounting

APS is exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels and emissions allowances and credits. As of December 31, 2007, APS hedged certain exposures to these risks for a maximum of 39 months.

Cash Flow Hedges

The changes in the fair value of APS’ hedged positions included in the APS Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2007, 2006 and 2005 are comprised of the following (dollars in thousands):


	2007		2006			2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	1,430	$	(5,666	)	$	14,452
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		—		(10	)		620
Gains from the discontinuance of cash flow hedges		150		178			473

During 2008, APS estimates that a net gain of $1 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).

131

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

The following table summarizes our assets and liabilities from risk management and trading activities in accordance with FIN 39-1 at December 31, 2007 and 2006 (dollars in thousands):


			Investments					Deferred
	Current		and Other		Current			Credits and
December 31, 2007	Assets		Assets		Liabilities			Other			Net Asset
Mark-to-market	$	2,815	$	41,603	$	(26,197	)	$	(4,573	)	$	13,648
Margin account		30,650		—		6,148			—			36,798
Collateral provided to counterparties		622		—		128			—			750
Collateral provided from counterparties		—		—		—			—			—

Total	$	34,087	$	41,603	$	(19,921	)	$	(4,573	)	$	51,196


				Investments					Deferred
	Current			and Other		Current			Credits and			Net Asset
December 31, 2006	Assets			Assets		Liabilities			Other			(Liability)
Mark-to-market	$	25,274		$	5,335	$	(51,985	)	$	(43,499	)	$	(64,875	)
Collateral provided to counterparties		—			—		500			1,359			1,859
Collateral provided from counterparties		(510	)		—		(90	)		—			(600	)
Margin account and options at cost		43,034			—		32,130			—			75,164

Total	$	67,798		$	5,335	$	(19,445	)	$	(42,140	)	$	11,548

See Note S-6 for discussion of the adoption of FIN 39-1.

S-4. Other Income and Other Expense

The following table provides detail of APS’ other income and other expense for 2007, 2006 and 2005 (dollars in thousands):

132

NOTES TO ARIZONA PUBLIC SERVICE COMPANY


	2007			2006			2005
Other income:
Interest income	$	10,961		$	16,526		$	14,513
SO2 emission allowance sales and other (a)		1,001			10,782			3,187
Investment gains — net		2,429			3,645			1,705
Miscellaneous		2,336			949			2,736

Total other income	$	16,727		$	31,902		$	22,141


Other expense:
Non-operating costs (a)	$	(12,712	)	$	(15,415	)	$	(11,706	)
Asset dispositions		(1,981	)		(1,851	)		(9,759	)
Miscellaneous		(6,937	)		(6,564	)		(1,739	)

Total other expense	$	(21,630	)	$	(23,830	)	$	(23,204	)


(a)		As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

S-5. Related Party Transactions

From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other subsidiaries. The following table summarizes the amounts included in the APS Statements of Income and Balance Sheets related to transactions with affiliated companies (dollars in millions):


	Year Ended December 31,
	2007		2006		2005
Electric operating revenues:
Pinnacle West Marketing & Trading(a)	$	4	$	6	$	6
Pinnacle West Energy		—		—		2

Total	$	4	$	6	$	8


Fuel and purchased power costs:
Pinnacle West Energy	$	—	$	—	$	61

Other:
Pinnacle West Energy interest income	$	—	$	—	$	7
Equity infusion from Pinnacle West	$	40	$	210	$	250


(a)		Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

133

NOTES TO ARIZONA PUBLIC SERVICE COMPANY


	As of December 31,
	2007			2006
Net affiliate receivables (payables):
Pinnacle West Marketing & Trading (a)	$	11		$	2
APSES		—			1
Pinnacle West		(9	)		(20	)

Total	$	2		$	(17	)


(a)		Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. However, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.”

On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consisted of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006. In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.

Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

S-6. Subsequent Events

APS adopted FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1) on January 1, 2008. In accordance with this guidance, APS elected to offset the fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting arrangement. Collateral was previously reported in other current assets or other current liabilities on our Consolidated Balance Sheet. The guidance requires retrospective application for all prior periods presented. As a result, APS’ Balance Sheet and Statement of Cash Flows line items decreased by the following amounts (dollars in thousands):

134

NOTES TO ARIZONA PUBLIC SERVICE COMPANY


	As originally		Reclassifications
	reported in the		as a result of the
	2007		adoption of			After adoption of
Balance Sheet - December 31, 2007	Form 10-K		FIN 39-1			FIN 39-1
Current Assets — Assets from risk management and trading activities	$	73,854	$	(39,767	)	$	34,087
Current Assets — Other current assets		17,296		(751	)		16,545
Investments and Other Assets — Assets from long-term risk management and trading activities		82,588		(40,985	)		41,603

Current Liabilities — Liabilities from risk management and trading activities		60,439		(40,518	)		19,921
Deferred Credits and Other - Liabilities from long-term risk management and trading activities		45,558		(40,985	)		4,573


	As originally		Reclassifications
	reported in the		as a result of the
	2007		adoption of			After adoption of
Balance Sheet - December 31, 2006	Form 10-K		FIN 39-1			FIN 39-1
Current Assets — Assets from risk management and trading activities	$	539,308	$	(471,510	)	$	67,798
Current Assets — Other current assets		13,367		(1,859	)		11,508
Investments and Other Assets — Assets from long-term risk management and trading activities		96,892		(91,557	)		5,335

Current Liabilities — Liabilities from risk management and trading activities		490,855		(471,410	)		19,445
Current Liabilities — Other current liabilities		74,728		(600	)		74,128
Deferred Credits and Other - Liabilities from long-term risk management and trading activities		135,056		(92,916	)		42,140

135

NOTES TO ARIZONA PUBLIC SERVICE COMPANY


				Reclassifications
	As originally			as a result of the
Statement of Cash Flows —	reported in the			adoption of			After adoption of
Year ended December 31, 2007	2007 Form 10-K			FIN 39-1			FIN 39-1
Change in risk management and trading — assets	$	40,376		$	(40,376	)	$	—
Change in margin and collateral accounts — assets		—			11,252			11,252
Change in risk management and trading — liabilities		(2,009	)		2,009			—
Change in margin and collateral accounts — liabilities		—			27,624			27,624
Collateral		509			(509	)		—

				Reclassifications
	As originally			as a result of the
Statement of Cash Flows —	reported in the			adoption of			After adoption of
Year ended December 31, 2006	2007 Form 10-K			FIN 39-1			FIN 39-1
Change in risk management and trading — assets	$	(74,208	)	$	74,208		$	—
Change in margin and collateral accounts — assets		—			(205,752	)		(205,752	)
Change in risk management and trading — liabilities		(121,833	)		121,833			—
Change in margin and collateral accounts — liabilities		—			(166,088	)		(166,088	)
Collateral		(175,799	)		175,799			—

				Reclassifications
	As originally			as a result of the
Statement of Cash Flows —	reported in the			adoption of			After adoption of
Year ended December 31, 2005	2007 Form 10-K			FIN 39-1			FIN 39-1
Other current assets	$	(2,592	)	$	300		$	(2,292	)
Change in risk management and trading — assets		15,449			(15,449	)		—
Change in margin and collateral accounts — assets		—			173,019			173,019
Change in risk management and trading — liabilities		115,495			(115,495	)		—
Change in margin and collateral accounts — liabilities		—			126,705			126,705
Collateral		169,080			(169,080	)		—

136

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF INCOME

(in thousands)


	Year Ended December 31,
	2007 (a)			2006			2005
Operating revenues	$	6,708		$	119,224		$	154,053


Operating expenses
Fuel and purchased power		(35,541	)		101,360			95,223
Other operating expenses		5,659			9,607			3,268

Total		(29,882	)		110,967			98,491


Operating income		36,590			8,257			55,562

Other
Equity in earnings of subsidiaries		287,078			324,504			58,759
Other income		225			2,208			5,337

Total		287,303			326,712			64,096

Interest expense		17,190			20,522			16,472


Income from continuing operations		306,703			314,447			103,186

Income tax benefit		(440	)		(12,898	)		(62,761	)


Income from continuing operations — net of income taxes		307,143			327,345			165,947
Income (loss) from discontinued operations		—			(90	)		10,320


Net income	$	307,143		$	327,255		$	176,267


(a)		Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

137

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(in thousands)


	Balance at December 31,
	2007 (a)			2006
Assets

Current assets
Cash and cash equivalents	$	137		$	11
Customer and other receivables		82,003			174,583
Allowance for doubtful accounts		—			(1,200	)
Assets from risk management and trading activities		—			44,620
Other current assets		1,262			2,682

Total current assets		83,402			220,696


Investments and other assets
Assets from long-term risk management and trading activities		—			62,314
Investments in subsidiaries		3,711,737			3,545,329
Deferred income taxes		11,806			—
Other assets		23,591			73,300

Total investments and other assets		3,747,134			3,680,943


Total Assets	$	3,830,536		$	3,901,639


Liabilities and Common Stock Equity

Current liabilities
Accounts payable	$	22,177		$	80,903
Accrued taxes		(86,081	)		(118,073	)
Short-term borrowings		115,000			27,900
Current maturities of long-term debt		—			115
Deferred income taxes		7,682			18,238
Liabilities from risk management and trading activities		2			57,618
Other current liabilities		18,019			77,495

Total current liabilities		76,799			144,196


Long-term debt less current maturities		175,000			175,000

Deferred credits and other
Deferred income taxes		—			19,582
Pension and other postretirement liabilities		22,248			13,437
Liabilities from risk management and trading activities		—			26,209
Other		24,878			23,218

Total deferred credits and other		47,126			82,446


Common stock equity
Common stock		2,133,733			2,587,201
Accumulated other comprehensive income (loss)		(15,863	)		17,512
Retained earnings		1,413,741			895,284

Total common stock equity		3,531,611			3,499,997


Total Liabilities and Common Stock Equity	$	3,830,536		$	3,901,639


(a)		Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

138

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31
	2007 (a)			2006			2005
Cash flows from operating activities
Net Income	$	307,143		$	327,255		$	176,267
Less: equity in earnings of subsidiaries — net		(287,078	)		(324,504	)		(58,759	)

Net income attributable to Pinnacle West		20,065			2,751			117,508
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		320			470			551
Deferred income taxes		(24,192	)		30,384			(19,929	)
Change in mark-to-market valuations		53,228			21,698			(15,162	)
Customer and other receivables		112,543			2,816			1,730
Accounts payable		(57,978	)		(55,675	)		43,969
Accrued taxes		25,127			(49,529	)		(84,758	)
Change in margin and collateral accounts — net		(11,602	)		75,605			(64,810	)
Other net		(104,968	)		(30,718	)		84,592

Net cash flow (used for) provided by operating activities		12,543			(2,198	)		63,691


Cash flows from investing activities
Investments in and advances to subsidiaries — net		(83,993	)		(4,677	)		(230,229	)
Repayments and advances of loans from subsidiaries		(4,800	)		2,686			2,402
Dividends received from subsidiaries		180,000			180,000			220,000
Purchases of investment securities		—			(147,501	)		(1,485,655	)
Proceeds from sale of investment securities		—			147,501			1,485,683

Net cash flow (used for) provided by investing activities		91,207			178,009			(7,799	)


Cash flows from financing activities
Issuance of long-term debt		—			175,000			—
Short-term borrowings and payments — net		87,371			27,900			—
Dividends paid on common stock		(210,473	)		(201,221	)		(186,677	)
Repayment of long-term debt		(115	)		(298,687	)		(165,104	)
Common stock equity issuance		19,593			35,834			290,542

Net cash flow used for financing activities		(103,624	)		(261,174	)		(61,239	)


Net increase (decrease) in cash and cash equivalents		126			(85,363	)		(5,347	)


Cash and cash equivalents at beginning of year		11			85,374			90,721


Cash and cash equivalents at end of year	$	137		$	11		$	85,374


(a)		Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.

139

PINNACLE WEST CAPITAL CORPORATION

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)


Column A	Column B		Column C				Column D		Column E
			Additions
	Balance at		Charged to		Charged				Balance
	beginning		cost and		to other				at end of
Description	of period		expenses		accounts		Deductions		period
Reserve for uncollectibles:
2007	$	5,597	$	4,130	$	—	$	4,945	$	4,782
2006		4,979		4,096		—		3,478		5,597
2005		4,896		2,638		—		2,555		4,979

140

ARIZONA PUBLIC SERVICE COMPANY

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)


Column A	Column B		Column C				Column D		Column E
			Additions
	Balance at		Charged to		Charged				Balance
	beginning		cost and		to other				at end of
Description	of period		expenses		accounts		Deductions		period
Reserve for uncollectibles:
2007	$	4,223	$	5,059	$	—	$	5,018	$	4,264
2006		3,568		4,096		—		3,441		4,223
2005		3,444		2,638		—		2,514		3,568

141

ITEM 9.01 FINANCIAL STATEMENTS AND EXHIBITS

(d) Exhibits


*Exhibit*
*No.*		*Registrant(s)*	*Description*
	12.1	Pinnacle West	Ratio of Earnings to Fixed Charges

	12.2	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements

	23.1	Pinnacle West	Consent of Deloitte & Touche LLP

	23.2	APS	Consent of Deloitte & Touche LLP

142

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	PINNACLE WEST CAPITAL CORPORATION (Registrant)
Dated: November 25, 2008	By:	/s/ James R. Hatfield
		James R. Hatfield Senior Vice President
		and Chief Financial Officer


	ARIZONA PUBLIC SERVICE COMPANY (Registrant)
Dated: November 25, 2008	By:	/s/ James R. Hatfield
		James R. Hatfield Senior Vice President
		and Chief Financial Officer

143

Arizona Public Service 8-KOther Events