Pinnacle West Capital - 10-K annual report

(Mark One)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

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     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or in any amendment to this Form 10-K. o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

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     State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of each registrant’s most recently completed second fiscal quarter:

     The number of shares outstanding of each registrant’s common stock as of March 7, 2006

     Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

     This combined Form 10-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 10-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.

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

APS Energy Services – APS Energy Services Company, Inc., a subsidiary of the Company

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

Financing Order – ACC Order that authorized APS’ $500 million loan to Pinnacle West Energy in May 2003

FIP – Federal Implementation Plan

Four Corners – Four Corners Power Plant

FSP – FASB Staff Position

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-hours, 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

NPC – Nevada Power Company

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts

Palo Verde – Palo Verde Nuclear Generating Station, also known as ANPP

Pinnacle West – Pinnacle West Capital Corporation, the Company

Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company

PPL Sundance – PPL Sundance Energy, LLC

PRP – potentially responsible parties under the Superfund Act

PSA – power supply adjustor

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

PX – California Power Exchange

RFP – request for proposals

RTO – regional transmission organization

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

Trading – energy-related activities entered into with the objective of generating profits on changes in market prices

2004 Settlement Agreement – an agreement proposing terms under which APS’ general rate case was settled, as approved by the ACC in 2005

VIE – variable-interest entity

WestConnect – WestConnect RTO, LLC, a proposed RTO to be formed by owners of electric transmission lines in the southwestern United States

          This Annual Report on Form 10-K is a combined report being filed by two separate registrants: Pinnacle West and APS. The information required with respect to each company is set forth within the applicable items.

          The Management’s Discussion and Analysis of Financial Condition and Results of Operations included under Item 7 of this report is divided into the following two sections:

          Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and Financial Statements of APS. Item 8 also includes Notes to Pinnacle West’s Consolidated Financial Statements, the majority of which also relate to APS, and Supplemental Notes to APS’ Financial Statements.

          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 significant subsidiaries are SunCor, which is engaged in real estate development and investment activities, and APS Energy Services, which provides competitive energy services and products in the western United States. 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 owns any generating plants and has ceased operations. Each of these subsidiaries, and El Dorado Investment Company, another subsidiary, are discussed in greater detail below. See “Business of SunCor Development Company,” “Business of APS Energy Services

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          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:

          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).

          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:

          The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must also approve any transfer 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.

          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 unconstitutional, 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. 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 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. APS cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

          APS is subject to varying degrees of competition from other investor-owned utilities in Arizona (such as Tucson Electric Power Company and Southwest Gas Corporation) as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit

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organizations (principally Salt River Project). APS also faces competition from low-cost, hydroelectric power and parties that have access to low-priced preferential, federal power and other governmental subsidies. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet their own energy requirements.

          General

          The FERC regulates rates for wholesale power sales and transmission services. During 2005, approximately 5.3% of APS’ electric operating revenues resulted from such sales and services. APS’ marketing and trading division focuses primarily on managing APS’ fuel and purchased power risks in connection with its costs of serving retail customer energy requirements. The division also sells, in the wholesale market, APS’ 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, the marketing and trading division, subject to specified parameters, markets, hedges and trades principally in electricity and fuels.

          Regional Transmission Organizations

          In a December 1999 order, the FERC established characteristics and functions that must be met by utilities in forming and operating RTOs. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and non-discriminatory markets and exclusive authority to maintain short-term reliability. On October 16, 2001, APS and other owners of electric transmission lines in the southwestern U.S. filed with the FERC a request for a declaratory order confirming that their proposal to form WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC’s RTO requirements and provide the basic framework for a standard market design for the southwestern United States. Since that time, APS and other supporters of the WestConnect efforts have been evaluating a phased approach to RTO implementation of regional structures in the desert Southwest.

          APS was incorporated in 1920 under the laws of the state of Arizona and currently has approximately 1,033,500 customers. APS does not distribute any products. During 2005, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 7.5% of electric revenues. See “Overview – General” and “Regulation and Competition” above for additional background information about APS’ business.

          At December 31, 2005, APS employed approximately 6,400 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).

          See “Properties – Capacity” in Item 2 for information about APS’ power plants by fuel types.

          2005 Energy Mix

          APS’ sources of energy during 2005 were: purchased power – 51.8%; coal – 26.3%; nuclear – 15.1%; and gas – 6.8%. In accordance with GAAP, a substantial portion of our purchased power contracts was netted against wholesale sales contracts on the Statements of Income. See Note 18 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.

          Coal Supply

          Cholla Cholla is a coal-fired power plant located in northeastern Arizona. It is a jointly-owned facility operated by APS. APS purchases most of Cholla’s coal requirements from coal suppliers that mine all of the coal under a long-term lease of coal reserves with the Navajo Nation, the federal government and private landholders. 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.

          Four Corners Four Corners is a coal-fired power plant located in the northwestern corner of New Mexico. It is a jointly-owned facility operated by APS. 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 July 2016, with options to extend the contract for five to fifteen additional years beyond the current plant site lease expiration in 2017.

          Navajo Generating Station The Navajo Generating Station is a coal-fired power plant located in northern Arizona. It is a jointly-owned facility operated by Salt River Project. 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 the current plant site lease expiration in 2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in 2019. Items that may impact the fuel price include lease provisions that allow for a renegotiation of the coal royalty in 2007 and 2017 and a fuel contract requirement for a five-year price review in 2007. In addition, the December 31, 2005 closure of the Mohave Generating Station has not had a significant impact on the cost structure for the Black Mesa – Kayenta Mine complex. APS does not have an ownership interest in the Mohave Generating Station, but understands the plant could be restarted. However, if the Mohave Generating Station is permanently closed, there is a potential for increased costs to the Navajo Generating Station, which is served by the Kayenta Mine. APS does not currently expect this matter to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.

          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 “Properties – Capacity” in Item 2 for information about APS’ ownership interests in Cholla, Four Corners and the Navajo Generating Station. See Note 11 of Notes to Pinnacle West’s

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Consolidated Financial Statements in Item 8 for information regarding APS’ coal mine reclamation obligations.

          Natural Gas Supply

          See Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of APS’ natural gas supply.

          Nuclear Fuel Supply

          Palo Verde Fuel Cycle Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. It is a jointly-owned facility operated by APS. The fuel cycle for Palo Verde is comprised of the following stages:

          The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2008. The Palo Verde participants have also contracted for all of Palo Verde’s enrichment services through 2010, 80% of 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 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of spent nuclear fuel and waste disposal.

          Purchased Power

          In addition to its own available generating capacity (see “Properties” in Item 2), APS purchases electricity under various arrangements. One of the most important of these is a long-term contract with Salt River Project. The amount of electricity available to APS is based in large part on customer demand within certain areas now served by APS pursuant to a related territorial agreement. The generating capacity available to APS pursuant to the contract is 350 MW. In 2005, APS received 552,014 MWh of energy under the contract and paid about $66.6 million for capacity availability and energy received. This contract may be canceled by Salt River Project on three years’ notice. By letter dated June 7, 2004, Salt River Project gave notice to APS to reduce capacity by 150 MW effective June 16, 2007. To date, this letter is the only notice Salt River Project has given under the contract. APS may also cancel the contract on five years’ notice, which may be given no earlier than December 31, 2006.

          In September 1990, APS entered into a thirty-year 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

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of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2005, APS received 571,492 MWh of energy under the capacity exchange. APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2005, PacifiCorp received offers of 1,090,700 MWh and purchased 372,473 MWh.

          APS continually assesses its need for additional capacity resources to assure system reliability. Under the terms of the 2004 Settlement Agreement, APS committed to seek proposals from the competitive wholesale market for filling its future resource needs. The current reliability RFP identifies the amount of capacity and energy needed to reliably meet expected customer demands and sought proposals for at least 1,000 MW of new generating capacity for 2007 and beyond. APS has entered into contracts for more than 650 MW of capacity and expects to finalize the remaining contract by the end of the first quarter of 2006.

          APS also has a renewable RFP seeking at least 100 MW of renewable capacity with a capability of producing at least 250,000 MWh annually. In accordance with the terms of the 2004 Settlement Agreement, power must be deliverable to the APS transmission system and its pricing must not exceed 125% of conventional resource alternatives. During 2005, APS conducted a competitive procurement process for renewable energy resources. The process resulted in the acquisition of approximately 145 MW of renewable energy resources via purchased power agreements. At an ACC Open Meeting on November 8, 2005, the ACC approved APS’ acquisition of out-of-state renewable resources. The ACC also ordered APS to work with the ACC staff to evaluate two in-state projects and report back within two months. APS has completed this evaluation process and has filed a report with the ACC. The ACC agreed with APS’ evaluation that the in-state projects were not economical.

          During the years 2003 through 2005, APS incurred approximately $1.7 billion in capital expenditures. APS’ capital expenditures for the years 2006 through 2008 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 $809 million in 2005. APS’ capital expenditures, including expenditures for environmental control facilities, for the years 2006 through 2008, net of contributions in aid of construction, have been estimated as follows (dollars in millions):

          The above amounts exclude capitalized interest costs and include capitalized property taxes and approximately $35 million per year for nuclear fuel. APS conducts a continuing review of its construction program.

          See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Needs and Resources by Company” in Item 7 for additional information about APS’ construction programs.

          EPA Environmental Regulation

          Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These regulations require states to submit state implementation plans by 2008 to make reasonable progress towards achieving natural visibility conditions in certain specified areas, including Class I Areas in the Colorado Plateau, and to consider and potentially apply the best available retrofit technology (“BART”) for major stationary sources.

          The rules allow nine western states and tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule. Five western states, including Arizona, have submitted proposed state implementation plans to the EPA to implement the Annex Rule.

          On February 18, 2005, the U.S. Court of Appeals for the District of Columbia granted a petition for review of the Annex Rule, filed by the Center for Energy and Economic Development (CEED). APS, Phelps Dodge Corporation, and the Environmental Defense were intervenors in the litigation in support of the EPA and the Annex Rule. Although the Court concluded that the EPA has the authority to promulgate a BART alternative, the Court ruled that the EPA must first conduct a BART analysis of eligible sources to demonstrate that the alternate plan would achieve greater emissions reductions than BART. On June 15, 2005, 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. On August 1, 2005, the EPA proposed a rule to, among other things, reconcile the Annex Rule with the CEED decision. We are currently evaluating the impact of this proposed rule. The Company cannot currently predict the outcome of this matter.

          Mercury On March 15, 2005, the EPA issued the Clean Air Mercury Rule to regulate 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 trading program. Under the trading program, the EPA has assigned each state a “budget” for reducing coal-fired power plant mercury emissions, 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 will be reduced from a total of 48 tons per year to 38 tons. In 2018, mercury emissions will be further reduced to 15 tons. APS is currently evaluating the potential impact of this rule and, as a result, cannot currently estimate the expenditures which may be required.

          By November 2006, the ADEQ will submit a state implementation plan to the EPA to implement the Clean Air Mercury Rule or an alternative mercury program, as authorized by the EPA. The mercury program for Four Corners will be implemented by EPA Region IX or, if it seeks and obtains program approval, by the Navajo Nation. APS is still evaluating the potential impacts of the state implementation plan on Cholla and of the Clean Air Mercury Rule on Cholla and Four Corners and cannot currently estimate the expenditures which may be required.

          On May 18, 2005, APS, Salt River Project and the Navajo Nation executed a Voluntary Compliance Agreement (“VCA”) to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. The fundamental premise of the VCA is that the Navajo Nation EPA may regulate air issues for Four Corners and the Navajo Generating Station only because the participants have agreed to submit to such regulation for the term of the agreement and under certain circumstances. If the EPA approves the Navajo Nation’s air programs consistent with the VCA, APS would seek dismissal of the pending litigation in the Navajo Nation Supreme Court and the pending litigation in the Navajo Nation District Court to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

          West Phoenix Power Plant

          During the period from November 2004 through March 2005, the Maricopa County Air Quality Department (“MCAQD”) issued a series of Notices of Violation (“NOVs”) to APS’ West Phoenix Power Plant that generally allege that the plant failed to comply with applicable permit requirements. APS is currently engaged in discussions with MCAQD concerning the NOVs. We do not expect the resolution of these matters to have a material adverse effect on our financial position, results of operations, or cash flows.

          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 before a state 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 Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As project manager 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 has not yet ruled on the petition. 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. APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore 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 operations of the plant for 2006 and later years. 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.

          On August 8, 2005, the President signed the Energy Policy Act of 2005 into law. The Company does not expect the Act to materially affect its operations.

          SunCor was incorporated in 1965 under the laws of the State 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 700 employees at December 31, 2005.

          At December 31, 2005, SunCor had total assets of about $487 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, mixed-use residential, commercial, office and industrial projects. During the past several years, SunCor has focused its business strategy on real estate development and investment activities.

          SunCor projects under development include five master-planned communities and several commercial and residential projects. The commercial and residential projects and two of the master-planned communities are in Arizona. Other master-planned communities are located near St. George, Utah, Boise, Idaho and Santa Fe, New Mexico.

          SunCor’s operating revenues were approximately $338 million in 2005, $350 million in 2004 and $362 million in 2003. SunCor’s net income was approximately $56 million in 2005, $45 million in 2004 and $56 million in 2003. 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 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.

          See Note 6 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 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.

          Pinnacle West Energy was incorporated in 1999 under the laws of the State of Arizona and was formerly engaged principally in the operation of unregulated generating plants. Pinnacle West Energy had approximately 30 employees as of December 31, 2005. Pinnacle West Energy’s principal offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-4145).

          Pinnacle West Energy transferred the PWEC Dedicated Assets to APS on July 29, 2005 and sold its 75% interest in Silverhawk to NPC on January 10, 2006. As a result Pinnacle West Energy no longer owns any generating plants and has ceased operations. At December 31, 2005, Pinnacle West Energy had total assets of $217 million, substantially all of which were assets held for sale related to Silverhawk.

          APS Energy Services was incorporated in 1998 under the laws of the State of Arizona and provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States. APS Energy Services had approximately 80 employees as of December 31, 2005. APS Energy Services’ principal offices are located at 400 East Van Buren Street, Phoenix, Arizona 85004 (telephone 602-250-5000).

          APS Energy Services had a net loss of $6 million in 2005, and net income of $3 million in 2004 and $16 million in 2003. At December 31, 2005, APS Energy Services had total assets of $88 million.

          El Dorado was incorporated in 1983 under the laws of the State 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 pretax income of $4 million in 2005, $40 million in 2004 and $7 million in 2003. Income taxes related to El Dorado are recorded by Pinnacle West. At December 31, 2005, El Dorado had total assets of $38 million.

          In addition to the factors affecting specific business operations identified in connection with the description of these operations contained elsewhere in this report, set forth below are risks and uncertainties that could affect our financial results.

          We are subject to comprehensive government regulation by several federal, state and local regulatory agencies that significantly affect our business and our results of operations.

          APS is subject to comprehensive regulation by several federal, state and local regulatory agencies that significantly influence its business and results of operations. The ACC regulates APS’ retail electric rates and APS’ issuance of securities. The ACC must also approve any transfer of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between us, APS and our respective affiliates. Our financial condition and results of operations are dependent upon the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. See Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.

          APS is required to have numerous permits, approvals and certificates from the agencies that regulate APS’ business. The FERC, the NRC, the EPA, and the ACC regulate many aspects of our utility operations, including siting and construction of facilities, customer service and, as noted in the preceding paragraph, the rates that APS can charge customers. We believe the necessary permits, approvals and certificates have been obtained for APS’ existing operations. However, changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations. We are also unable to predict the impact on our business and operating results from pending or future regulatory activities of any of these agencies.

          As noted above, our financial condition and results of operations are dependent upon the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. These proceedings consist of a general retail rate case, an application for an emergency interim rate increase, and an application for two separate surcharges under the PSA. See Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8. We cannot predict the timing or the outcome of these proceedings or the resulting levels of regulated revenues.

          We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact our business plans, or expose us to environmental liabilities.

          We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid

waste, and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.

          In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

          We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from APS’ customers, could have a material adverse effect on our financial position, results of operations or cash flows.

          There are inherent risks in the operation of nuclear facilities, such as environmental, health and financial risks and the risk of terrorist attack.

          Through APS, we have an ownership interest in and operate, on behalf of a group of owners, Palo Verde, which is the largest nuclear electric generating facility in the United States. Palo Verde is subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the costs of securing the facilities against possible terrorist attacks and unscheduled outages due to equipment and other problems. We maintain nuclear decommissioning trust funds and external insurance coverage to minimize our financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage.

          The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.

          Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on our business and our financial results.

          In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. Retail competition could have a significant adverse financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Although some very limited retail competition existed in the service area of APS in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

          As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, and wholesale power marketers and brokers. This increased competition could affect our load forecasts, plans for power supply and wholesale energy sales and related revenues. As a result of the changing regulatory environment and the relatively low barriers to entry, we expect wholesale competition to increase.

          Our results of operations can be adversely affected by milder weather.

          Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our overall operating results fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish our results of operations and harm our financial condition.

          Our cash flow largely depends on the performance of our subsidiaries.

          We conduct our operations primarily through subsidiaries. Substantially all of our consolidated assets are held by such subsidiaries. Accordingly, our cash flow is dependent upon the earnings and cash flows of these subsidiaries and their distributions to us. The subsidiaries are separate and distinct legal entities and have no obligation to make distributions to us.

          The debt agreements of some of our subsidiaries may restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. An ACC financing order requires APS to indefinitely maintain a common equity ratio of at least 40% and does not allow APS to pay common dividends if the payment would reduce its common equity below that threshold. As defined in the ACC financing order approving the arrangement, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At December 31, 2005, APS’ common equity ratio, as defined, was approximately 54%.

          Our ability to meet our debt service obligations could be adversely affected because our debt securities are structurally subordinated to the debt securities and other obligations of our subsidiaries.

          Because we are structured as a holding company, all existing and future debt and other liabilities of our subsidiaries will be effectively senior in right of payment to our debt securities. None of the indentures under which we or our subsidiaries may issue debt securities limits our ability or the ability of our subsidiaries to incur additional debt in the future. The assets and cash flows of our subsidiaries will be available, in the first instance, to service their own debt and other obligations. Our ability to have the benefit of their assets and cash flows, particularly in the case of any insolvency or financial distress affecting our subsidiaries, would arise only through our equity ownership interests in our subsidiaries and only after their creditors have been satisfied.

          If we are not able to access capital at competitive rates, our ability to implement our financial strategy will be adversely affected.

          We rely on access to short-term money markets, longer-term capital markets and the bank markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:

     Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by:

          A further reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.

          We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade could increase our borrowing costs, which would diminish our financial results. We would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under certain of our existing credit facilities depend on our credit ratings. A downgrade could also require us to provide additional support in the form of letters of credit or cash or other collateral to various counterparties. If our short-term ratings were to be lowered, it could limit our access to the commercial paper market. We note that the ratings from rating agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.

          The use of derivative contracts in the normal course of our business and changing interest rates and market conditions could result in financial losses that negatively impact our results of operations.

          Our operations include managing market risks related to commodity prices and, subject to specified risk parameters, engaging in marketing and trading activities intended to profit from market price movements. We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances. We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions 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 commodity.

          We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material adverse impact on our earnings for a given period.

          Changing interest rates will affect interest paid on variable-rate debt and interest earned on variable-rate securities in our pension plan and nuclear decommissioning trust funds. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan is also impacted by the discount rate, which is the interest rate used to discount future pension obligations. Declining interest rates impact the discount rate, and may result in increases in pension costs, cash contributions, and charges to other comprehensive income. The pension plan and nuclear decommissioning trust funds also have risks associated with changing market values of fixed income and equity investments. A significant portion of the pension costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices.

          In preparing our financial statements in accordance with accounting principles generally accepted in the United States of America, management must often make estimates and assumptions

     The market price of our common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond our control:

          In addition, the stock market in general has experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of our common stock.

          We may enter into credit and other agreements from time to time that restrict our ability to pay dividends.

          Payment of dividends on our common stock may be restricted by credit and other agreements entered into by us from time to time. At December 31, 2005, there were no material restrictions on our ability to pay dividends under any such agreement.

          Neither Pinnacle West nor APS has received written comments regarding its periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of its 2005 fiscal year and that remain unresolved.

     APS’ present generating facilities have capacities as follows:

     APS’ 2005 peak one-hour demand on its electric system was recorded on July 18, 2005 at 6,999,600 kW, compared with the 2004 peak of 6,402,100 kW recorded on August 11, 2004. Taking into account additional capacity then available to APS under long-term purchase power contracts as well as APS’ generating capacity, APS’ capability of meeting system demand on July 18, 2005, amounted to 6,383,000 kW, for an installed reserve margin of negative 13.3%. 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 2005 peak amounted to 3,820,000 kW, for a margin of a negative 51.4%. Firm purchases totaling 4,653,000 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 19.3%.

     See “Business of Arizona Public Service Company – Purchased Power and Generating Fuel – Purchased Power” in Item 1 for information about certain of APS’ long-term power agreements.

     The Navajo Generating Station and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. These are long-term agreements with options to extend, and APS does not believe that the risks with respect to enforcement of these easements and leases are material. The majority of coal contracted for use in these plants and certain associated transmission lines are also located on Indian reservations. See “Business of Arizona Public Service Company – Purchased Power and Generating Fuel – Coal Supply” in Item 1.

     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.

     In 2004, the NRC determined that there had been a safety concern with Palo Verde’s procedures related to safety injection system piping. This led to a “yellow” finding under the NRC’s inspection criteria and put Palo Verde in the “degraded safety cornerstone” column of the NRC’s performance matrix, resulting in a supplemental NRC inspection. The NRC completed its supplemental inspection during 2005 and issued its report, closing one finding and indicating it would follow up on another finding at some later time upon notice from APS.

     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 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional information about APS’ nuclear decommissioning costs.

     Palo Verde Liability and Insurance Matters

     See “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

     Jointly-Owned Facilities

     APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2005:

     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 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.

     APS’ transmission facilities consist of approximately 5,613 pole miles of overhead lines and approximately 42 miles of underground lines, 5,457 miles of which are located within the State of Arizona. APS’ distribution facilities consist of approximately 12,262 pole miles of overhead lines and approximately 14,430 miles of underground lines, all of which are located within the State of Arizona.

     See “Business of Arizona Public Service Company – Environmental Matters” and “Water Supply” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’ power plants.

     See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” in Item 7 for a discussion of issues relating to Palo Verde Unit 1.

     See “Business of Arizona Public Service Company – Construction Program” in Item 1 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 for a discussion of APS’ construction program.

     See “Business of SunCor Development Company” in Item 1 for information regarding SunCor’s properties. Substantially all of SunCor’s debt is collateralized by interests in certain real property.

     See “Business of Arizona Public Service Company – Environmental Matters” and “– Water Supply” in Item 1 with regard to pending or threatened litigation and other disputes.

     See Note 11 of Notes to the Pinnacle West Consolidated Financial Statements in Item 8 with regard to a lawsuit against APS and the other Navajo Generating Station participants and for information relating to the FERC proceedings on California energy market issues.

     Not applicable.

Pinnacle West’s executive officers are as follows:

     The executive officers of Pinnacle West are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and their principal occupations (in addition to those stated in the table) of such officers for the past five years have been as follows:

     Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the following capacities: from August 1999 to February 2001 as President; from February 1997 to February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr. Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until October 2002. Mr. Post is also a director of APS, Pinnacle West Energy and Phelps Dodge Corporation.

     Mr. Davis was elected President effective February 2001 and Chief Operating Officer effective September 2003. Prior to that time he was Chief Operating Officer and Executive Vice President of Pinnacle West (April 2000 – February 2001) and Executive Vice President, Commercial Operations of APS (September 1996 – October 1998). Mr. Davis is also President of APS (since October 1998) and Chief Executive Officer of APS (since October 2002). He is a director of APS and Pinnacle West Energy.

     Mr. Brandt was elected to his present position in September 2003 and was Senior Vice President and Chief Financial Officer (December 2002 – September 2003). Prior to that time, he was Senior Vice President and Chief Financial Officer of Ameren Corporation (diversified energy services company). Mr. Brandt was elected Executive Vice President and Chief Financial Officer of APS in September 2003. He was also Senior Vice President and Chief Financial Officer of APS (January 2003 – September 2003).

     Mr. Flores was elected to his present position in September 2003. Prior to that time, he was Executive Vice President, Corporate Business Services of Pinnacle West (July 1999 – September 2003). He was also Executive Vice President, Corporate Business Services of APS (October 1998 – July 1999).

     Mr. Froggatt was elected to his present position in October 2002. Prior to that time, he was Vice President and Controller of Pinnacle West (August 1999 – October 2002), Controller of Pinnacle West (July 1999 – August 1999) and Controller of APS (July 1997 – July 1999).

     Ms. Gomez was elected to her present position in February 2004. Prior to that time, she was Treasurer (August 1999 – February 2004) and Manager, Treasury Operations of APS (1997 – 1999). She was also elected Treasurer of APS in October 1999 and Vice President of APS in February 2004.

     Mr. Levine was elected Executive Vice President of APS in July 1999 and President and Chief Executive Officer of Pinnacle West Energy in January 2003. Prior to that time, he was Senior Vice President, Nuclear Generation of APS (September 1996 – July 1999).

     Ms. Loftin was elected Vice President and General Counsel in July 1999 and Secretary in October 2002. She was also elected Vice President and General Counsel of APS in July 1999 and Secretary of APS in October 2002.

     Mr. Robinson was elected to his present position in September 2003. Prior to that time, he was Vice President, Finance and Planning of APS (October 2002 – September 2003), Vice President, Regulation and Planning of Pinnacle West (June 2001 – October 2002) and Director, Accounting, Regulation and Planning of Pinnacle West (prior to June 2001).

     Mr. Wheeler was elected to his present position in September 2003. Prior to that time, he was Senior Vice President, Regulation, System Planning and Operations of APS (October 2002 – September 2003) and Senior Vice President, Transmission, Regulation and Planning of Pinnacle West and APS (June 2001 – October 2002). Prior to that time he was a partner with Snell & Wilmer L.L.P.

     Pinnacle West’s common stock is publicly held and is traded on the New York and Pacific Stock Exchanges. At the close of business on March 7, 2006, Pinnacle West’s common stock was held of record by approximately 32,846 shareholders.

QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE STOCK SYMBOL: PNW

     APS’ common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for APS’ common stock.

     The chart below sets forth the dividends declared on APS’ common stock for each of the four quarters for 2005 and 2004.

     The sole holder of APS’ common stock, Pinnacle West, is entitled to dividends when and as declared out of funds legally available therefor. As of December 31, 2005, APS did not have any outstanding preferred stock.

     Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.

     The ACC regulates APS’ retail electric rates. The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 3, APS has pending before the ACC:

     APS has been operating Palo Verde Unit 1 at reduced power levels since December 25, 2005 due to a non-safety related acoustic impact in one of the unit’s shutdown cooling lines. Unit 1 is currently operating at approximately 25% power. APS has concluded after comprehensive analysis that the preferred solution will require Unit 1 to undergo an outage of approximately five weeks in order for APS to effect the necessary modifications to the Unit. APS anticipates that Unit 1 will begin this outage in the June timeframe. In addition, an outage for preparatory work of approximately one week, beginning March 18, 2006, will take place prior to this outage. This preferred solution was initially planned for installation in the spring of 2007. APS estimates that, through February 28, 2006, Unit 1’s reduced power level has resulted in incremental replacement power costs of approximately $20 million after income taxes, approximately $18 million of which has been incurred since January 1, 2006. Based on current forward market energy prices, APS estimates that (a) operating Unit 1 at reduced power levels until the assumed outage in the June timeframe will result in additional incremental replacement power costs of approximately $25 million after income taxes and (b) the June Unit 1 outage will result in additional incremental replacement power costs of approximately $15 million after income taxes. APS estimates that these reduced power levels and the June Unit 1 outage will result in additional PSA deferrals of $50 million after tax ($85 million pretax) in 2006. See “Deferred Fuel and Purchased Power Costs” below.

     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow. Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and

industrial retail customers in the western United States. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures.

     Pinnacle West Energy is our subsidiary that previously owned and operated unregulated generating plants. Pursuant to the ACC’s April 7, 2005 order in APS’ 2003 rate case, on July 29, 2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. See “APS 2003 Rate Case” in Note 3. Pinnacle West Energy sold its 75% interest in Silverhawk to NPC on January 10, 2006. As a result Pinnacle West Energy no longer owns any generating plants and has ceased operations.

     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction. We plan to expand long-term resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.

     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.

     We have three principal business segments (determined by products, services and the regulatory environment):

     The following table summarizes net income for 2005, 2004 and 2003 (dollars in millions):

     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less fuel and purchased power costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with Securities and Exchange Commission rules. Exhibit 99.29 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior year amounts to conform to our current-period presentation.

     In June 2005, we entered into an agreement to sell our 75% interest in Silverhawk to NPC. As a result of the sale, we recorded an after-tax loss from discontinued operations of approximately $56 million in the second quarter of 2005. The marketing and trading segment discontinued operations in the chart above include this loss as well as revenues and expenses related to the operations of Silverhawk. The sale was completed on January 10, 2006.

     The settlement of APS’ 2003 general retail rate case became effective April 1, 2005. As part of the settlement, the ACC approved a 4.2% annual retail rate increase and the PSA, which provides mechanisms for adjusting rates to reflect variations in fuel and purchased power costs. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual fuel and purchased power costs, net of Off-System Sales margins, and the amount for such costs currently included in base rates. The current base rate for fuel and purchased power costs is based on 2003 price levels and spot prices for natural gas and wholesale power have increased over 40% since then. Although APS defers actual fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and ACC approval of periodic surcharge applications.

     Actual fuel and purchased power costs are higher than in prior periods primarily due to higher fuel prices and increased plant outage days.

     APS’ pretax PSA deferrals were approximately $173 million at December 31, 2005. Based on recent forward market prices for natural gas and purchased power (which are subject to change), and assuming no interim rate relief, APS estimates that its pretax PSA deferrals in 2006 will be approximately $240 million to $250 million. In January 2006, the ACC approved the first annual adjustment under the PSA mechanism, which is expected to recover approximately $110 million of the 2005 balance of $173 million from retail customers over twelve months beginning February 1, 2006. In this same order, the ACC granted APS the authority to continue to defer fuel costs in excess of the $776.2 million annual fuel cost cap established in the 2005 rate order and to seek recovery of those amounts in a future proceeding. On February 2, 2006, APS filed a request with the ACC to recover the remainder of the retail portion of the 2005 deferred fuel balance of $173 million — approximately $60 million — through two surcharges. The first surcharge is to recover $15 million over a twelve-month period proposed to begin with the date of the ACC’s decision in APS’ pending emergency interim rate case. The second surcharge is to recover approximately $45 million over a twelve-month period proposed to begin no later than the ACC’s completion of its inquiry regarding unplanned 2005 outages at Palo Verde. The $45 million of PSA deferrals represents additional replacement power costs associated with these outages. See Note 3. See “Overview” in this Item 7 for information about Palo Verde Unit 1 operating at reduced power levels and the related economic impact.

     Our consolidated net income for 2005 was $176 million compared with $243 million for the prior year. The current-year net income included an after-tax net loss from discontinued operations of $47 million compared with a $4 million after-tax loss in the prior year, which for both years is related primarily to the sale and operations of Silverhawk (see “Sale of Silverhawk” above), partially offset by sales of commercial properties at SunCor. Income from continuing operations decreased $24 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

     Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $202 million higher for 2005 compared with the prior year primarily as a result of:

     Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $49 million lower for 2005 compared with the prior year primarily as a result of:

     Real Estate Revenues

     Real estate revenues were $12 million lower for 2005 compared with the prior year primarily due to decreased parcel sales, partially offset by increased home sales at SunCor.

     Other revenues were $18 million higher for 2005 compared with the prior year primarily due to increased sales of energy-related products and services by APS Energy Services.

     Our consolidated net income for 2004 was $243 million compared with $241 million for the prior year. 2004 net income included an after-tax net loss from discontinued operations of $4 million primarily related to Silverhawk. The 2003 net income included a $16 million after-tax gain from discontinued operations primarily related to sales of commercial properties at SunCor. Income from continuing operations increased $22 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

     Additional details on the major factors that increased (decreased) income from continuing operations and net income are contained in the following table (dollars in millions):

     The increase in net costs (primarily interest expense, depreciation and operations and maintenance expense, net of gross margin contributions) related to new power plants placed in service in mid-2003 and mid-2004 by Pinnacle West Energy totaled approximately $26 million after income taxes in 2004 compared with the prior year.

     Regulated electricity segment revenues were $57 million higher for 2004 compared with the prior year primarily as a result of:

     Marketing and trading segment revenues were $9 million higher for 2004 compared with the prior year primarily as a result of:

     Other revenues were $15 million higher for 2004 compared with the prior year primarily due to higher non-commodity revenues at APS Energy Services.

     Capital Expenditure Requirements

     The following table summarizes the actual capital expenditures for the year ended 2005 and estimated capital expenditures for the next three years:

     Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth.

     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants, the acquisition of the Sundance Plant and the replacement of Palo Verde steam generators (see below). Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Generation also includes nuclear fuel expenditures of approximately $35 million annually for 2006 through 2008.

     Replacement of the steam generators at Palo Verde Unit 1 was completed during the fall 2005 outage at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of one additional set of steam generators. These generators will be installed in Unit 3 and are scheduled for completion in the fall of 2007 at an approximate cost of $75 million (APS’ share). Approximately $20 million of the Unit 3 steam generator costs have been incurred through 2005 with the remaining $55 million included in future years in the capital expenditure table above. Capital expenditures will be funded with internally generated cash or external financings.

     The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2005 (dollars in millions):

     Off-Balance Sheet Arrangements

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

     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under

certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2005, APS would have been required to assume approximately $234 million of debt and pay the equity participants approximately $185 million.

     Guarantees and Letters of Credit

     We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Consolidated Balance Sheets with respect to these obligations. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 21 for additional information regarding guarantees and letters of credit.

     Credit Ratings

     The ratings of securities of Pinnacle West and APS as of March 7, 2006 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 18).

     Debt Provisions

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt to capitalization ratio. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For each of

Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At December 31, 2005, the ratio was approximately 49% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage is approximately 4 times under APS’ bank financing agreements as of December 31, 2005. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.

     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, in the event of a further rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

     All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under 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.

     Pinnacle West (Parent Company)

     Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. On October 19, 2005, our Board of Directors increased the common stock dividend to an indicated annual rate of $2.00 per share from $1.90 per share, effective with the December 1, 2005 dividend payment. The level of our common dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

     Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2003 through 2005, total dividends from APS were $510 million and total cash contributions from SunCor were $243 million. For the year ended December 31, 2005 cash contributions from APS were approximately $170 million and distributions from SunCor were approximately $50 million. An ACC financing 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. At December 31, 2005, APS’ common equity ratio, as defined, was approximately 54%.

     At December 31, 2005, Pinnacle West’s outstanding long-term debt, including current maturities, was $299 million. In December 2005, we replaced the existing revolving credit facility with 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, 2005, we had no commercial paper or short-term borrowings outstanding. We ended 2005 in an invested position.

     Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our subsidiaries. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. The assets in the plan are comprised of common stocks, bonds, common and collective trusts and short-term investments. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. We contributed $53 million in 2005. The contribution to our pension plan in 2006 is estimated to be approximately $50 million. The expected contribution to our other postretirement benefit plans in 2006 is estimated to be approximately $29 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

     On May 2, 2005, Pinnacle West redeemed at par all of its $165 million Floating Rate Senior Notes due November 1, 2005. The Company used cash on hand to redeem the notes.

     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 a portion of such funds to acquire the Sundance Plant and fund other capital expenditures to meet the growing needs of APS’ service territory.

     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”). Pinnacle West will use the proceeds of the Series A Notes to repay at maturity a portion of the $300 million aggregate principal amount of its 6.40% Senior Notes due April 1, 2006 or for other general corporate purposes.

     See “Equity Infusions” in Note 3 for information regarding the ACC approval of Pinnacle West’s infusion of more than $450 million of equity into APS, consisting of about $250 million of the proceeds of Pinnacle West’s common equity issuance and about $210 million of the proceeds from the sale of Silverhawk in January 2006.

     APS

     APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.

     On January 15, 2005, APS repaid its $100 million 6.25% Notes due 2005. APS used cash on hand to redeem these notes.

     On March 1, 2005, Maricopa County, Arizona Pollution Control Corporation issued $164 million of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Maricopa County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Balance Sheets.

     On May 12, 2003, APS issued $500 million of debt and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to Pinnacle West to fund the repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. On April 11, 2005, this loan was repaid with the proceeds of a new debt issuance by Pinnacle West Energy.

     On August 1, 2005, APS repaid $300 million of its 7.625% Notes due 2005. APS used cash on hand to repay these notes.

     On August 22, 2005, APS issued $250 million of 5.50% Senior Unsecured Notes due September 1, 2035. A portion of the net proceeds from the sale of the notes was used for general corporate purposes and, on October 3, 2005, APS used the balance of the proceeds, along with cash on hand, to fund the $500 million that it was obligated to transfer to Pinnacle West Energy in connection with APS’ acquisition of the PWEC Dedicated Assets. See “Related Party Transactions” in Note S-6 for information regarding the $500 million intercompany payable to Pinnacle West Energy. APS satisfied this obligation to Pinnacle West Energy on October 3, 2005.

     APS’ outstanding debt was approximately $2.6 billion at December 31, 2005. In December 2005, APS replaced its $325 million revolving credit facility that would have terminated in May 2007 with a $400 million revolving credit facility that terminates in December 2010. This line of credit is 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. At December 31, 2005, APS had no outstanding commercial paper or bank borrowings. APS ended 2005 in an invested position.

     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.

     See “Deferred Fuel and Purchased Power Costs” above and “Power Supply Adjustor” in Note 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 PSA adjustments and ACC approval of periodic surcharge applications.

     See “Cash Flow Hedges” in Note 18 for information related to increased collateral provided to us by counterparties.

     On April 11, 2005, Pinnacle West Energy issued $500 million Floating Rate Senior Notes due April 1, 2007. Pinnacle West unconditionally guaranteed these notes. Pinnacle West Energy used the proceeds of this issuance to repay the $500 million loan from APS to Pinnacle West Energy described under “Capital Needs and Resources — APS” above. On October 3, 2005, Pinnacle West

Energy repaid the Floating Rate Senior Notes due April 1, 2007 with $500 million received from APS in connection with the transfer of the PWEC Dedicated Assets.

     See Note 22 of Notes to Consolidated Financial Statements above for a discussion of the sale of our 75% ownership interest in Silverhawk.

     Other Subsidiaries

     During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures during 2005 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’s total outstanding debt was approximately $145 million as of December 31, 2005, including $123 million of debt outstanding, which is classified as long-term debt, under a $150 million line of credit. SunCor’s total short-term debt was $16 million at December 31, 2005. SunCor’s long-term debt, including current maturities, totaled $129 million at December 31, 2005. 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.

     APS Energy Services expects minimal capital expenditures over the next three years.

     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 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 $324 million, including $173 million related to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31, 2005. Included in the $173 million is approximately $45 million related to the 2005 unplanned Palo Verde outages, which currently are the subject of inquiry by the ACC. In addition, we had $592 million of regulatory liabilities on the Consolidated Balance Sheets at December 31,

2005, which primarily are related to removal costs. See Notes 1 and 3 for more information about regulatory assets, APS’ general rate case and power supply adjustor.

     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, 2005 projected benefit obligation, our December 31, 2005 reported pension liability on the Consolidated Balance Sheets and our 2005 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):

     The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2005 accumulated other postretirement benefit obligation and our 2005 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):

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

     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 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. For cash flow hedges, the effective portion of changes in the fair value of the derivative are 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.

     General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity rates and tariffs and variations in weather from period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition.

     Retail Rate Proceedings The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 3, APS has pending before the ACC a general retail rate case, an application for an emergency interim rate increase, and an application for two separate surcharges under the PSA.

     Fuel and Purchased Power Costs Fuel and purchased power costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service, variances in deferrals and amortization of fuel and purchased power beginning on April 1, 2005 and our hedging program for managing such costs. See “Power Supply Adjustor” in Note 3 for information regarding the PSA approved by the ACC. See “Natural Gas Supply” in Note 11 for more information on fuel costs. See “Overview” in this Item 7 for information about Palo Verde Unit 1 operating at reduced power levels and the related economic impact.

     Customer and Sales Growth The customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory averaged about 3.8% a year for the three years 2003 through 2005; we currently expect customer growth to average about 3.8% per year from 2006 to 2008. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.7% on average, from 2006 through 2008, before the effects of weather variations. Customer growth for 2005 was 4.3%.

     Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors can result in increases or decreases in annual net income of up to $10 million.

     Weather In forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

     Wholesale Power Market Conditions The marketing and trading division focuses primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. The marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and

credits. Our future earnings will be affected by the strength or weakness of the wholesale power market.

     Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.

     Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction or acquisition, changes in depreciation and amortization rates (see Note 1), and changes in regulatory asset amortization. See Note 7 for information on APS’ acquisition of the Sundance Plant in 2005. See “Purchased Power” in Part I, Item 1 of this report, for more information on requests for proposal to acquire additional long-term resources in 2006 and 2007.

     Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed value for 2005 and 2004. We expect property taxes to increase as new power plants, the acquisition of the Sundance Plant and our additions to transmission and distribution facilities are included in the property tax base.

     Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation. Interest expense is also affected by interest rates on variable-rate debt.

     Retail Competition Although some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

     Subsidiaries SunCor’s net income was $56 million in 2003, $45 million in 2004 and $56 million in 2005. See Note 22 for further discussion.

     APS Energy Services’ and El Dorado’s historical results are not indicative of future performance.

     General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.

     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

     Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund (see Note 12). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The nuclear decommissioning fund also has risk associated with the changing market value of equity 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, 2005 and 2004. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2005 and 2004 (dollars in thousands):