EX-99.1 17 p68820exv99w1.htm EX-99.1 exv99w1
 

Exhibit 99.1

PINNACLE WEST RISK FACTORS
(2003 Annual Report on Form 10-K)

     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 APS’ general rate case pending before the ACC.

     As required by a 1999 settlement agreement among Arizona Public Service Company (“APS”) and various parties (the “1999 Settlement Agreement”), on June 27, 2003, APS filed a general rate case with the Arizona Corporation Commission (the “ACC”). APS requested a $175.1 million, or 9.8%, increase in its annual retail electricity revenues, to become effective July 1, 2004. The major reasons for the request include:

  •   complying with the provisions of the 1999 Settlement Agreement;
 
  •   incorporating significant increases in fuel and purchased power costs, including results of purchases through the ACC’s “Track B” procurement process;
 
  •   recognizing changes in APS’ cost of service, cost allocation and rate design;
 
  •   obtaining rate base recognition of the generating plants built in Arizona by Pinnacle West Energy Corporation (“Pinnacle West Energy”) since 1999 to serve APS’ retail electricity customers, specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3 (the “PWEC Dedicated Assets”);
 
  •   recovering $234 million written off by APS as a result of the 1999 Settlement Agreement; and
 
  •   recovering restructuring and compliance costs associated with the ACC’s electric competition rules.

     The general rate case will also address the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized in the 1999 Settlement Agreement, would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the ACC retail competition rules described below. If APS does not have a rate adjustment mechanism that allows it to recover its full costs of procuring fuel for its generating plants, then changes in fuel prices may increase its cost of producing power or decrease the amount it receives from selling power, harming our financial performance. On November 4, 2003, the ACC approved the issuance of an order which authorizes a rate adjustment mechanism allowing APS to recover changes in purchased power costs (but not changes in fuel costs) incurred after July 1, 2004. The other rate adjustment mechanisms authorized in the 1999 Settlement Agreement (such as the costs associated with complying with the ACC electric competition rules) were also tentatively approved for subsequent implementation in the general rate case. The purchased power rate adjustment mechanism will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend or modify, in all respects, this November 4 order during the rate case.

     In its filed testimony in the rate case, the ACC staff recommended, among other things, that the ACC decrease APS’ rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in APS’ rate base, and not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings, and access to capital markets. We believe the ACC will be able to make a decision by the end of 2004. We cannot predict the outcome of the rate case and the resulting levels of regulated revenues.

 

 

     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. As part of the ACC’s approval of a $500 million financing arrangement between APS and Pinnacle West Energy, APS must maintain a common equity ratio of at least 40% and may not 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, 2003, APS’ common equity ratio was approximately 46%.

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

     We are, directly and through our subsidiaries, subject to governmental regulation that may have a negative impact on our business and results of operations. We are a “holding company” within the meaning of the Public Utility Holding Company Act (“PUHCA”); however, we are exempt from the provisions of PUHCA by virtue of our filing of an annual exemption statement with the SEC.

     APS is subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influence its operating environment and may affect its ability to recover costs from utility customers. APS is required to have numerous permits, approvals and certificates from the agencies that regulate APS’ business. The Federal Energy Regulatory Commission (“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 APS can charge customers. We believe the necessary permits, approvals and certificates have been obtained for APS’ existing operations. However, we are unable to predict the impact on our business and operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.

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

     The 1999 Settlement Agreement limits APS’ ability to change retail rates until at least July 1, 2004, which could have a significant adverse financial impact on us if wholesale power prices significantly exceed the amount included for generation costs in APS’ current bundled retail rates. Under the ACC’s rules, APS is the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in APS’ cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last three years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS’ current retail rates. APS regularly makes short-term seasonal purchases of power, and may experience unforeseen increases in load demand or generation or transmission outages, requiring APS to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power. In addition, APS filed a general rate case with the ACC on June 27, 2003 (see discussion above). Among other things, the rate case will address the implementation of rate adjustment mechanisms, which would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the ACC retail competition rules.

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     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 rating 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;
 
  •   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 credit agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.

     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. In 1999, the ACC approved rules that provide a framework for the introduction of retail electric competition in Arizona. Under the rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its 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 APS had planned to transfer its generation assets to Pinnacle West Energy. Pursuant to an

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ACC order dated September 10, 2002, the ACC unilaterally modified the 1999 Settlement Agreement and directed APS to cancel any plans to divest interests in any of its generating assets. The ACC further established a requirement that APS 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 APS’ requirements in the summer months through September 2006. 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 APS’ service area 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. As competition continues to increase, our financial position and results of operations could be adversely affected.

     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 credit ratings agencies also have increased their level of scrutiny. We believe that we are complying 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.

     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, 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.

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     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 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. 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 credit 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.

     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, APS and other owners of electric transmission lines in the Southwest 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 Southwest. On September 15, 2003, the FERC issued an order granting clarification and rehearing, in part, of its prior orders. In particular, this order approved the use of a physical congestion management scheme, which is used to allocate transmission rights on congested lines, for WestConnect for an initial phase-in period. FERC indicated that the WestConnect utilities and the appropriate regional state advisory committee should develop a market-based congestion management scheme for subsequent implementation. APS is now participating in a cost/benefit analysis of implementing WestConnect, the results of which are expected to be completed in 2004.

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

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

     We are subject to numerous environmental 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 results of operations.

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

     In preparing the financial statements in accordance with generally accepted accounting principles, 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 the 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 $165 million of regulatory assets on the Consolidated Balance Sheets at December 31, 2003.
 
  •   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, plan funding requirements 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 or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in common stock equity (as a component of other comprehensive income (loss)).
 
  •   Mark-to-Market Accounting — The market 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

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      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.

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