EXHIBIT 99.32

APS RISK FACTORS

(Report on Form 10-K for the fiscal year ended December 31, 2004)

     Set forth below and in other documents we file with the Securities and Exchange Commission are risks and uncertainties that could affect our financial results.

     We cannot predict the outcome of our general rate case pending before the Arizona Corporation Commission (the “ACC”).

     On June 27, 2003, we filed a request with the ACC to increase annual retail electricity revenues by approximately $175.1 million, or 9.8%, effective July 1, 2004. On August 18, 2004, a substantial majority of the parties to the rate case, including us, the ACC staff, the Residential Utility Consumer Office, other customer groups, and merchant power plant intervenors entered into an agreement that proposes terms under which the rate case would be settled (the “2004 Settlement Agreement”). The 2004 Settlement Agreement is subject to ACC approval. Key financial components of the 2004 Settlement Agreement are as follows:

•   We would receive an annual retail rate increase of approximately $75.5 million, or 4.21%. The increase would consist of an increase in base rates of approximately 3.77% and an increase of approximately 0.44% for recovery over five years of the past costs of our compliance with the ACC’s retail electric competition rules (the “Rules”).

•   We would acquire from Pinnacle West Energy Corporation (“Pinnacle West Energy”) Redhawk Combined Cycle Units 1 and 2, West Phoenix Combined Cycle Units 4 and 5, and Saguaro Combustion Turbine Unit 3 (collectively, the “Dedicated Assets”), with a net carrying value of approximately $850 million, and rate base the Dedicated Assets at a rate base value of $700 million, which would result in a regulatory rate base disallowance of $148 million. As a result, for financial reporting purposes, we would recognize a one-time, after-tax net plant write-off of approximately $88 million in the period when the plant transfer to us is completed, and would reduce annual depreciation expense by approximately $5 million.

•   To bridge the time between the effective date of the rate increase and the actual date the Dedicated Assets transfer, we and Pinnacle West Energy would enter into a cost-based purchase power agreement (the “Bridge PPA”), which would be based on the value of the Dedicated Assets described in the previous bullet point. The Bridge PPA would remain in effect until the Federal Energy Regulatory Commission (the “FERC”) approves the transfer of the Dedicated Assets to us and the transfer is completed.

•   If the FERC were to issue an order denying our request to acquire the Dedicated Assets, the Bridge PPA would become a 30-year purchased power agreement, with prices reflecting cost-of-service as if we had acquired and rate-based the Dedicated Assets at the value described above.

•   If the FERC were to issue an order (a) approving our request to transfer the Dedicated Assets at a value materially less than $700 million, (b) approving the transfer of fewer than all of the Dedicated Assets, or (c) that was materially inconsistent with the 2004 Settlement Agreement, we would file an appropriate application with the ACC so that rates could be adjusted. In these circumstances, the Bridge PPA would continue at least until the conclusion of the subsequent proceeding to consider any appropriate adjustment to our rates.

•   A power supply adjuster (“PSA”) would provide for the recovery of fuel and purchased power costs, subject to specified parameters and procedures.

•   We would not restore and recover in rates the $234 million write-off recorded in 1999 as a result of a 1999 settlement agreement approved by the ACC related to the implementation of retail electric competition in Arizona (the “1999 Settlement Agreement”).

•   We would adopt longer service lives than originally requested for certain depreciable assets.

     On February 28, 2005, the administrative law judge in the general rate case issued a recommended order. The recommended order proposes ACC approval of the 2004 Settlement Agreement with two changes related to the

PSA. First, the amount of gas costs that we could recover under the annual PSA would be limited to $500 million per year. Second, although the 2004 Settlement Agreement provides that the PSA would remain in effect for a minimum five-year period, under the recommended order the ACC would be able to eliminate the PSA at any time, if appropriate, if we file a rate case before the expiration of the five-year period or if we do not comply with the terms of the PSA. If we exceed the gas costs that could be recoverable under the PSA or if the ACC eliminates the PSA, we would retain the right to file a rate case to reset our base rates. We cannot predict the outcome of this matter.

     The procurement of wholesale power by us without the ability to adjust retail rates could have an adverse impact on our business and financial results.

     Although the Rules allow retail customers to have access to competitive providers of energy and energy services, under the Rules, we are the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. In the event of shortfalls of electricity due to unforeseen increases in load demand or generation or transmission outages, we may need to purchase additional supplemental power in the wholesale spot market. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. There can be no assurance that we would be able to fully recover the costs of this power. Although the proposed settlement of our general rate case would, among other things, allow us to recover purchased power costs, there can be no assurance that the 2004 Settlement Agreement will be approved by the ACC as proposed.

     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.

     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. Under the Rules, as modified by the 1999 Settlement Agreement, we were required to transfer all of our competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. To satisfy this requirement, we had planned to transfer our generation assets to Pinnacle West Energy. Pursuant to an ACC order dated September 10, 2002, the ACC unilaterally modified the 1999 Settlement Agreement and directed us to cancel any plans to divest interests in any of our generating assets. The ACC further established a requirement that we solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. Pinnacle West Energy bid on and entered into contracts to supply most of our requirements in the summer months through September 2006. In addition, as discussed above, a proposed settlement of our general rate case would result in Pinnacle West Energy transferring a significant amount of generation assets to us. These regulatory developments and legal challenges to the Rules have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our 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. As competition continues to increase, our financial position and results of operations could be adversely affected.

     We are subject to complex government regulation that may have a negative impact on our business and our results of operations.

     We are subject to governmental regulation that may have a negative impact on our business and results of operations. We are a “subsidiary company” of a “holding company” within the meaning of the Public Utility Holding Company Act of 1935 (“PUHCA”); however, we are exempt from the provisions of PUHCA (except Section 9(a)(2) thereof) by virtue of the filing of an annual exemption statement with the Securities and Exchange Commission (the “SEC”) by our parent company, Pinnacle West Capital Corporation (“Pinnacle West”).

     We are subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influence our operating environment and may affect our ability to recover costs from utility customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business.

The FERC, the Nuclear Regulatory Commission (“NRC”), the Environmental Protection Agency (“EPA”), and the ACC regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. We believe the necessary permits, approvals and certificates have been obtained for our 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.

     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 our customers, could have a material adverse effect on our results of operations.

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

     We have an ownership interest in and operate, on behalf of a group of owners, the Palo Verde Nuclear Generating Station (“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.

     The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.

     The uncertain outcome regarding the creation of regional transmission organizations, or RTOs, and implementation of the FERC’s standard market design may materially impact our operations, cash flows or financial position.

     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 nondiscriminatory markets and exclusive authority to maintain short-term reliability. Additionally, in a pending notice of proposed rulemaking, the

FERC is considering implementing a standard market design for wholesale markets. On October 16, 2001, we and other owners of electric transmission lines in the southwestern U.S. filed with the FERC a request for a declaratory order confirming that our 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 U.S. Since that time, we have been evaluating a phased approach to RTO implementation in the desert Southwest. We are currently participating with other entities in the southwestern U.S. in a cost/benefit analysis of implementing the WestConnect RTO, the results of which are expected to be completed in 2005.

     If we ultimately join an RTO, we could incur increased transmission-related costs and receive reduced transmission service revenues; we may be required to expand our transmission system according to decisions made by the RTO rather than our internal planning process; and we may experience other impacts on our operations, cash flows or financial position that will not be quantifiable until the final tariffs and other material terms of the RTO are known.

     Recent events in the energy markets that are beyond our control may have negative impacts on our business.

     As a result of the energy crisis in California during the summer of 2001, the recent volatility of natural gas prices in North America, the filing of bankruptcy by the Enron Corporation, and investigations by governmental authorities into energy trading activities, companies generally in the regulated and unregulated utility businesses have been under an increased amount of public and regulatory scrutiny. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are in material compliance with all applicable laws, but it is difficult or impossible to predict or control what effect these or related issues may have on our business or our access to the capital markets.

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.

     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 or a downgrade of our credit ratings may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:

•   an economic downturn;

•   capital market conditions generally;

•   the bankruptcy of an unrelated energy company;

•   increased market prices for electricity and gas;

•   terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies; or

•   the overall health of the utility industry.

     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:

•   increasing the cost of future debt financing;

•   increasing our vulnerability to adverse economic and industry conditions;

•   requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; and

•   placing us at a competitive disadvantage compared to our competitors that have less debt.

     A significant 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 and credits. 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 by 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. Continuation of recent decreases in the discount rate would 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 equity investments. A significant portion of the pension costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices.

     Actual results could differ from estimates used to prepare our financial statements.

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

•   Regulatory Accounting - Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of

costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $135 million of regulatory assets on our balance sheet at December 31, 2004. A component of the 2004 Settlement Agreement, which is subject to ACC approval, would allow us to acquire the Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and rate base the Dedicated Assets at a rate base value of $700 million. This would result in a mandatory rate base disallowance of approximately $150 million. As a result, for financial reporting purposes, we would recognize a one-time, after-tax net plant write-off of approximately $90 million in the period when the plant transfer to us is completed and would reduce annual depreciation expense by approximately $5 million.

•   Pensions and Other Postretirement Benefit Accounting - Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

•   Derivative Accounting - Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine 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, changes in the fair value of the derivative are recognized in common stock equity (as a component of other comprehensive income (loss)).