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Exhibit 99.1 APS 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 our general rate case pending before the
Arizona Corporation Commission (the ACC). As required by a 1999 settlement agreement among us and various parties
(the 1999 Settlement Agreement), on June 27, 2003, we filed a general rate
case with the ACC. We requested a $175.1 million, or 9.8%, increase in our
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 our 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 our 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 us 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 us 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 we do not have a rate adjustment mechanism that allows us
to recover our full costs of procuring fuel for our generating plants, then
changes in fuel prices may increase our cost of producing power or decrease the
amount we receive 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 us 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 our rates by approximately 8%
(approximately $143 million annually), not allow the PWEC Dedicated Assets to
be included in our rate base, and not allow us 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.




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We are subject to complex government regulation which 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
(PUHCA); however, we are exempt from the provisions of PUHCA by virtue of the
filing of an annual exemption statement with 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 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 we can charge customers. We believe the necessary permits,
approvals and certificates have been obtained for our 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 us without the ability to adjust
retail rates could have an adverse impact on our business and financial
results. The 1999 Settlement Agreement limits our 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 our current bundled retail rates. Under the ACCs
rules, we are 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
us 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 our 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 our current retail rates. We regularly make
short-term seasonal purchases of power, and may experience unforeseen
increases in load demand or generation or transmission outages,
requiring us to purchase additional supplemental power in the
wholesale spot market. Unless we are able to obtain an adjustment of our rates under the
emergency provisions of the 1999 Settlement Agreement, there can be no
assurance that we would be able to fully recover the costs of this power. In
addition, we 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 us 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. 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; 2




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
    
    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, 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
planned to transfer 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.
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. 3




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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. 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 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. 4




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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, we and other owners of electric
transmission lines in the Southwest 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 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. We are now participating in a
cost/benefit analysis of implementing WestConnect, the results of which are
expected to be completed in 2004. If
we ultimately join an RTO, we could incur increased
transmission-related costs and 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. 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. 5




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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. 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 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
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. 6